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10-K 1 d22803e10vk.htm FORM 10-K e10vk

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-K


(Mark One)
þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2004

or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission file number 1-4174

The Williams Companies, Inc.

(Exact name of Registrant as Specified in Its Charter)


Delaware		73-0569878
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)

One Williams Center, Tulsa, Oklahoma		74172
(Address of Principal Executive Offices)		(Zip Code)

918-573-2000

(Registrant’s Telephone Number, Including Area Code)

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


		Name of Each Exchange
Title of Each Class		on Which Registered

Common Stock, $1.00 par value		New York Stock Exchange and Pacific Stock Exchange
Preferred Stock Purchase Rights		New York Stock Exchange and Pacific Stock Exchange
	Income PACs	New York Stock Exchange

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

5.50% Junior Subordinated Convertible Debentures due 2033

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

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes þ No o

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second quarter was approximately $6,216,391,365.

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

DOCUMENTS INCORPORATED BY REFERENCE

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

THE WILLIAMS COMPANIES, INC.

FORM 10-K

TABLE OF CONTENTS


				Page

PART I
Items 1 and 2.	Business and Properties				1
	Website Access to Reports and Other Information				1
	General				1
	Recent Developments				2
	Financial Information About Segments				3
	Business Segments				3
		General overview			3
		Power			4
			Power overview		4
			Power details		4
		Gas pipeline			7
			Gas pipeline overview		7
			Gas pipeline details		7
		Exploration & production			13
			Exploration & production overview		13
			Exploration & production details		13
		Midstream			18
			Midstream overview		18
			Midstream details		18
		Other			22
		Additional business segment information			23
	Environmental Matters				23
	Employees				23
	Forward Looking Statements/ Risk Factors and Cautionary Statement for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995				23
	Risk Factors				24
	Financial Information about Geographic Areas				34
Item 3.	Legal Proceedings				35
Item 4.	Submission of Matters to a Vote of Security Holders				36
Item 4A.	Executive Officers of the Registrant				36
PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters				37
Item 6.	Selected Financial Data				38
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations				39
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk				85
Item 8.	Financial Statements and Supplementary Data				90


		Page

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		173
Item 9A.	Controls and Procedures		173
Item 9B.	Other Information		173
PART III
Item 10.	Directors and Executive Officers of the Registrant		173
Item 11.	Executive Compensation		174
Item 12.	Security Ownership of Certain Beneficial Owners and Management		174
Item 13.	Certain Relationships and Related Transactions		175
Item 14.	Principal Accounting Fees and Services		175
PART IV
Item 15.	Exhibits, Financial Statement Schedules		176
Restated Certificate of Incorporation
Second Amendment to Supplemental Retirement Plan
Form of 2004 Deferred Stock Agreement
Form of 2004 Performance-Based Deferred Stock Agreement
Amendment Agreement
Comptuation of Ratio of Earnings to Combined Fixed Charges
Subsidiaries
Consent of Ernst & Young LLP
Consent of Netherland, Sewell & Associates, Inc.
Consent of Miller and Lents, LTD.
Power of Attorney
Certification of the CEO Pursuant to Section 302
Certification of the CFO Pursuant to Section 302
Certification of the CEO and CFO Pursuant to Section 906

DEFINITIONS

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


	Bcfe — means one billion cubic feet of gas equivalent determined using the ratio of one barrel of oil or condensate to six thousand cubic feet of natural gas.

	British Thermal Unit or BTU — means a unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit.

	BBtud — means one billion BTUs per day.

	Dekatherms or Dth or Dt — means a unit of energy equal to one million BTUs.

	Mbbls/d — means one thousand barrels per day.

	Mcfe — means one thousand cubic feet of gas equivalent using the ratio of one barrel of oil or condensate to six thousand cubic feet of natural gas.

	Mdt/d — means one thousand dekatherms per day.

	MMcf — means one million cubic feet.

	MMcf/d — means one million cubic feet per day.

	MMcfe — means one million cubic feet of gas equivalent using the ratio of one barrel of oil or condensate to six thousand cubic feet of natural gas.

	MMdt — means one million dekatherms.

iii

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 (Exchange Act). You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, N.W., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SEC’s Internet website at http://www.sec.gov.

Our Internet website is http://www.williams.com. We make available free of charge on or through our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Code of Ethics, Board committee charters and Code of Business Conduct are also available on our Internet website.

GENERAL

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

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

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

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

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


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

RECENT DEVELOPMENTS

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

Asset sales

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

Cost reduction efforts

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

Debt retirement and restructuring

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

Addressing Power issues

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

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

Disciplined growth

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


	•	Drilling 1,384 gross successful natural gas wells.

	•	Completion of more than 500 well connections to our natural gas gathering systems in Wyoming and New Mexico.

	•	The operational start of our Devil’s Tower floating production system and associated pipelines in the deepwater Gulf of Mexico.

	•	Completion of a new, nine mile, natural gas pipeline lateral in western Washington to deliver an additional 113,000 dekatherms per day of gas.

Other events

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

FINANCIAL INFORMATION ABOUT SEGMENTS

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

BUSINESS SEGMENTS

General overview

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


	•	Power — manages our wholesale power and natural gas commodity businesses through purchases, sales and other related transactions, under our wholly-owned subsidiary Williams Power Company and its subsidiaries.

	•	Gas Pipeline — includes our interstate natural gas pipelines and pipeline joint venture investments organized under our wholly-owned subsidiary, Williams Gas Pipeline Company, LLC.

	•	Exploration & Production — produces, develops and manages natural gas reserves primarily located in the Rocky Mountain and Mid-Continent regions of the United States and is comprised of several wholly-owned subsidiaries including Williams Production Company LLC and Williams Production RMT Company.

	•	Midstream — includes our natural gas gathering, treating and processing business and is comprised of several wholly-owned subsidiaries including Williams Field Services Group, Inc. and Williams Natural Gas Liquids, Inc.

	•	Other — consists of corporate operations and certain continuing operations previously reported within the International and Petroleum Services segments. Other also includes our interest in Longhorn Partners Pipeline, L.P. (Longhorn).

This report is organized to reflect this structure.

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

Power


	*Power overview*


	•	Our Power segment, formerly known as Energy Marketing & Trading, is an energy services provider that buys, sells and transports energy and energy-related commodities, primarily power and natural gas, on a wholesale level.

	•	In 2004 we continued to focus on reducing risk and maximizing expected cash flows in our Power segment. Following our decision to retain Power in September 2004, we also focused on executing new contracts to hedge our portfolio and support our natural gas businesses.


	*Power details*

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

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


Location	Megawatts

California		4,141
Alabama		844
Louisiana		749
New Jersey		766
Pennsylvania		669
Michigan		541

Total		7,710

We use portions of the electricity produced under the tolling agreements to supply obligations under counterparty-tailored arrangements known as full requirements contracts. Under full requirements contracts, we supply the electricity required by our counterparties to serve their customers. Through full requirements contracts, we supply approximately 1,869 megawatts of electricity to our customers in Georgia and Pennsylvania.

Through tolling resale agreements, we enter into transactions that mirror, to varying degrees, some or all of our rights under our underlying tolling arrangements, which remain in place with our tolling counterparties.

We have resold part of our rights (1,045 to 1,175 megawatts) under the California tolling arrangement to the California Department of Water Resources through 2010.

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

In 2004, we marketed natural gas throughout North America with total physical volumes averaging 2.5 billion cubic feet per day. With approximately 10 percent of this natural gas, we fuel electric generating plants we own or in which we have contractual rights. We sell approximately 70 percent of this natural gas to customers including local distribution companies, utilities, producers, industrials and other gas marketers. With the remaining 20 percent, we procure gas supply for our Midstream operations, sell gas produced by Exploration & Production and manage firm service contracts for Gas Pipeline.

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

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


	Operating statistics

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


		Year Ending December 31,

		2004		2003		2002

U.S. Operations
Marketing and trading physical volumes:
	Power (thousand megawatt hours)		93,998		165,908		404,711
	Natural Gas (billion cubic feet per day)		2.3		2.7		3.8
	Petroleum products (thousand barrels per day)		50		77		832


		2004		2003		2002

European Operations
Marketing and trading physical volumes:
	Power (thousand megawatt hours)		—		—		26,094
	Natural Gas (billion cubic feet per day)		—		—		0.2
	Petroleum products (thousand barrels per day)		—		23		83

In 2004, Power managed 2.5 billion cubic feet per day of natural gas. The natural gas volumes managed include the following (in billion cubic feet per day):


	2004

Sales to third parties		1.7
Sales to other segments		.6
For use in tolling agreements and by owned generation		.2

Total natural gas managed		2.5

As of December 31, 2004, our Power segment had approximately 284 customers compared with 234 customers at the end of 2003.


	Regulatory and legal matters

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

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


	Competition and market environment

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

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

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


	Ownership of property

Power’s primary assets are its term contracts, related systems and technological support. In addition, affiliates of Power own the Hazelton and Milagro generating facilities described above. As discussed further in Note 1 of our Notes to Consolidated Financial Statements, derivative contracts in our portfolio have been recognized at their estimated fair value. According to generally accepted accounting principles (GAAP), fair

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


	Environmental matters

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


	*Gas pipeline overview*


	•	We own one of the nation’s largest interstate natural gas pipeline systems with 14,700 miles of interstate natural gas pipelines for transportation of natural gas across the country to utilities and industrial customers.

	•	Our pipelines include Transcontinental Gas Pipe Line Corporation (Transco), Northwest Pipeline Corporation (Northwest Pipeline) and several pipeline joint ventures.

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


	*Gas pipeline details*

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

Construction of the Gulfstream gas pipeline project which consists of a natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida, commenced in June 2001. In December 2001, Gulfstream filed an application with the FERC to allow Gulfstream to complete the construction of its approved facilities in phases. In May 2002, the first phase of the project was placed into service at a cost of approximately $1.5 billion. The second phase of the project was placed into service on February 1, 2005. The total estimated capital cost of both phases of the project is approximately $1.7 billion. At December 31, 2004, our investment in Gulfstream was $726 million.

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

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


	Regulatory matters

Gas Pipeline’s interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978, and, as such, its rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. Each gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979 and the Pipeline Safety Improvement Act of 2002, which regulate safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. Cardinal Pipeline Company, LLC, an intrastate natural gas pipeline company that is operated and 45 percent owned by Gas Pipeline, is subject to the jurisdiction of the North Carolina Utilities Commission.

Each of our interstate natural gas pipeline companies establishes its rates primarily through the FERC’s ratemaking process. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related income taxes and (3) volume throughput assumptions. The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the demand and commodity rates also impact profitability. As a result of these proceedings, certain revenues previously collected may be subject to refund. See Note 15 of our Notes to Consolidated Financial Statements for the amounts accrued for potential refund at December 31, 2004.


	Competition

The FERC has taken various actions to strengthen market forces in the natural gas pipeline industry which has led to increased competition throughout the industry. In a number of key markets, interstate pipelines are now facing competitive pressures from other major pipeline systems, enabling local distribution companies and end users to choose a supplier or switch suppliers based on the short-term price of gas and the cost of transportation. We expect competition for natural gas transportation to continue to intensify in future years due to increased customer access to other pipelines, rates, competitiveness among pipelines, customers’ desire to have more than one transporter, shorter contract terms, and regulatory developments. Future utilization of pipeline capacity will depend on competition from other pipelines, use of alternative fuels, the general level of natural gas demand, and weather conditions. Electricity and distillate fuel oil are the primary competitive forms of energy for residential and commercial markets. Coal and residual fuel oil compete for industrial and electric generation markets. Nuclear and hydroelectric power and power purchased from electric transmission grid arrangements among electric utilities also compete with gas-fired electric generation in certain markets.

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

any significant financial impact from “capacity turnback.” We anticipate that we will be able to remarket most future capacity subject to capacity turnback, although competition may cause some of the remarketed capacity to be sold at lower rates or for shorter terms.

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


	Ownership of property

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


	Environmental matters

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

For a discussion of specific environmental issues involving the interstate pipelines, including estimated cleanup costs associated with certain pipeline activities, see “Environmental” under Management’s Discussion and Analysis of Financial Condition and Results of Operations and “Environmental Matters” in Note 15 of our Notes to Consolidated Financial Statements.


	Principal Companies in the Gas Pipeline Segment

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


	*Transcontinental Gas Pipe Line Corporation (Transco)*

Transco is an interstate natural gas transportation company that owns and operates a 10,500-mile natural gas pipeline system extending from Texas, Louisiana, Mississippi and the offshore Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Pennsylvania, and New Jersey to the New York City metropolitan area. The system serves customers in Texas and eleven southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, New York, New Jersey, and Pennsylvania. Effective May 1, 1995, Transco transferred the operation of certain production area facilities to Williams Field Services Group, Inc. (Williams Field Services), an affiliated company and part of the Midstream segment. Effective June 1, 2004 and due in part to FERC Order No. 2004, the operation of the production area facilities was transferred back to Transco.


	Pipeline system and customers

At December 31, 2004, Transco’s system had a mainline delivery capacity of approximately 4.7 MMdt of natural gas per day from its production areas to its primary markets. Using its Leidy Line that originates at the Canadian border in western New York along with market-area storage capacity, Transco can deliver an additional 3.4 MMdt of natural gas per day for a system-wide delivery capacity total of approximately

8.1 MMdt of natural gas per day. Transco’s system includes 44 compressor stations, five underground storage fields, two liquefied natural gas (LNG) storage facilities and four processing plants. Compression facilities at a sea level-rated capacity total approximately 1.5 million horsepower.

Transco’s major natural gas transportation customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on Transco’s system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. One customer accounted for approximately 11 percent of Transco’s total revenues in 2004. Transco’s firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Transco’s business. Additionally, Transco offers storage services and interruptible transportation services under short-term agreements.

Transco has natural gas storage capacity in five underground storage fields located on or near its pipeline system or market areas and operates three of these storage fields. Transco also has storage capacity in a LNG storage facility and operates the facility. The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 216 billion cubic feet of gas. In addition, wholly-owned subsidiaries of Transco operate and hold a 35 percent ownership interest in Pine Needle LNG Company, an LNG storage facility with four billion cubic feet of storage capacity. Storage capacity permits Transco’s customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.


	Expansion projects


	*Central New Jersey Expansion Project*

The Central New Jersey Expansion Project will involve an expansion of Transco’s existing natural gas transmission system in Transco’s Zone 6 from the Station 210 pooling point to locations along Transco’s Trenton-Woodbury Line. The project will create approximately 105 Mdt/d of new firm transportation capacity, which has been fully subscribed by one shipper for a twenty-year primary term. The project facilities will include approximately 3.5 miles of pipeline loop at an estimated capital cost of $13 million. Transco filed an application for FERC approval of the project on August 11, 2004, which the FERC approved on February 10, 2005. The target in-service date for the project is November 1, 2005.


	*Leidy to Long Island Expansion Project*

The Leidy to Long Island Expansion Project will involve an expansion of our existing natural gas transmission system in Zone 6 from the Leidy Hub in Pennsylvania to Long Island, New York. The project will provide 100 Mdt/d of firm transportation capacity, which has been fully subscribed by one shipper for a twenty-year primary term. The project facilities will include pipeline looping in Pennsylvania and looping and a natural gas compressor facility in New Jersey. Based on the results of the open season for the project and the incorporation of existing capacity made available through a reverse open season, the estimated capital cost of the project has been reduced to $103 million. We expect that nearly three-quarters of the project expenditures will occur in 2007. The FERC has granted our request to initiate a pre-application environmental review, soliciting early input from citizens, governmental entities and other interested parties to identify and address potential siting issues. We expect to file a formal application with the FERC in September 2005. The target in-service date for the project is November 1, 2007.


	Operating statistics

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


			2004		2003		2002

			(In trillion British
			Thermal Units)
Market-area deliveries:
	Long-haul transportation			782		771		824
	Market-area transportation			817		802		777

		Total market-area deliveries		1,599		1,573		1,601
Production-area transportation				317		297		179

		Total system deliveries		1,916		1,870		1,780

Average Daily Transportation Volumes				5.2		5.1		4.9
Average Daily Firm Reserved Capacity				6.6		6.5		6.4

Transco’s facilities are divided into eight rate zones. Five are located in the production area, and three are located in the market area. Long-haul transportation involves gas that Transco receives in one of the production-area zones and delivers to a market-area zone. Market-area transportation involves gas that Transco both receives and delivers within the market-area zones. Production-area transportation involves gas that Transco both receives and delivers within the production-area zones.


	*Northwest Pipeline Corporation (Northwest Pipeline)*

Northwest Pipeline is an interstate natural gas transportation company that owns and operates a natural gas pipeline system extending from the San Juan Basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington. Northwest Pipeline provides services for markets in California, New Mexico, Colorado, Utah, Nevada, Wyoming, Idaho, Oregon and Washington directly or indirectly through interconnections with other pipelines.


	Pipeline system and customers

At December 31, 2004, Northwest Pipeline’s system, having long-term firm transportation agreements with peaking capacity of approximately 3.4 MMdt of natural gas per day, was composed of approximately 4,200 miles of mainline and lateral transmission pipelines and 42 compressor stations having sea level-rated capacity of approximately 462,000 horsepower.

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

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

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

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

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

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

In 2004, Northwest Pipeline served a total of 175 transportation and storage customers. Transportation customers include distribution companies, municipalities, interstate and intrastate pipelines, gas marketers and direct industrial users. The two largest customers of Northwest Pipeline in 2004 accounted for approximately 13.9 percent and 11.3 percent, of its total operating revenues. No other customer accounted for more than 10 percent of Northwest Pipeline’s total operating revenues in 2004. Northwest Pipeline’s firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Northwest Pipeline’s business. Additionally, Northwest Pipeline offers interruptible and short-term firm transportation service.

As a part of its transportation services, Northwest Pipeline utilizes underground storage facilities in Utah and Washington enabling it to balance daily receipts and deliveries. Northwest Pipeline also owns and operates a LNG storage facility in Washington that provides service for customers during a few days of extreme demands. These storage facilities have an aggregate firm delivery capacity of approximately 600 million cubic feet of gas per day.


	Operating statistics

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


	2004		2003		2002

	(In trillion British
	Thermal Units)
Total Throughput		650		682		729
Average Daily Throughput		1.8		1.9		2.0
Average Daily Reserved Capacity Under Long-Term Base Firm Contracts, excluding peak capacity		2.5		2.3		2.3
Average Daily Reserved Capacity Under Short-Term Firm Contracts(1)		.6		.8		.5


(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


	*Exploration & production overview*


	•	We produce, develop, 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 approximately 3.0 trillion cubic feet equivalent of proved natural gas reserves in the United States as of December 31, 2004.

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.


	*Exploration & production details*

Our Exploration & Production segment, which is comprised of several wholly owned subsidiaries, including Williams Production Company LLC and Williams Production RMT Company (RMT), produces, develops, and manages natural gas reserves primarily located in the Rocky Mountain and Mid-Continent regions of the United States. We specialize in natural gas production from tight-sands formations and coal bed methane reserves in the Piceance, San Juan, Powder River and Arkoma basins. Over 99 percent of Exploration & Production’s domestic reserves are natural gas. Our Exploration & Production segment also has international oil and gas interests, which include a 69 percent equity interest in APCO Argentina, an oil and gas exploration and production company with operations in Argentina, and a 10 percent interest in the La Concepcion area located in western Venezuela.

Exploration & Production’s primary strategy is to utilize its expertise in the development of tight-sands and coal bed methane reserves. Exploration & Production’s current proved undeveloped and probable reserves provide us with strong capital investment opportunities for several years into the future. Exploration & Production’s goal is to drill its existing proved undeveloped reserves, which comprise nearly 55 percent of proved reserves and to drill in areas of probable reserves. In addition, Exploration & Production provides a significant amount of equity production that is gathered and/or processed by our Midstream facilities in the San Juan basin.

Information for our Exploration & Production segment relates only to domestic activity unless otherwise noted.


	Pledged assets

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


	Oil and gas properties

Exploration & Production’s properties are located primarily in the Rocky Mountain and Mid-Continent regions of the United States. Rocky Mountain properties are located primarily in New Mexico, Wyoming and Colorado. All our Mid-Continent properties are located in Oklahoma. We use the terms “gross” to refer to all wells or acreage in which we have at least a partial working interest and “net” to refer to our ownership represented by that working interest.


	*Rocky Mountain properties*


	Piceance Basin

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


	San Juan Basin

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


	Powder River Basin

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


	*Mid-Continent properties*


	Arkoma Basin

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


	*Other properties*

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


	Gas reserves and wells

The following table summarizes our natural gas reserves as of December 31 (using prices at December 31 held constant) for the year indicated:


	2004		2003		2002

	(Bcfe)
Proved developed natural gas reserves		1,348		1,165		1,368
Proved undeveloped natural gas reserves		1,638		1,538		1,466

Total proved natural gas reserves		2,986		2,703		2,834

The following table summarizes our proved natural gas reserves by basin as of December 31, 2004:


	Percentage of
Basin	Proved Reserves

Piceance		61%
San Juan		23%
Powder River		10%
Arkoma, Green River and Gulf Coast		6%

		100%

No major discovery or other favorable or adverse event has caused a significant change in estimated gas reserves since year-end 2004. We have not filed on a recurring basis estimates of our total proved net oil and gas reserves with any U.S. regulatory authority or agency other than the Department of Energy (DOE) and the SEC. The estimates furnished to the DOE have been consistent with those furnished to the SEC, although Exploration & Production has not yet filed any information with respect to its estimated total reserves at December 31, 2004, with the DOE. Certain estimates filed with the DOE may not necessarily be directly comparable due to special DOE reporting requirements, such as the requirement to report gross operated reserves only. The underlying estimated reserves for the DOE did not differ by more than five percent from the underlying estimated reserves utilized in preparing the estimated reserves reported to the SEC.

Approximately 99 percent of our year-end 2004 United States proved reserves estimates were either audited by Netherland, Sewell & Associates, Inc., or, in the case of reserves estimates related to properties underlying the Williams Coal Seam Gas Royalty Trust, were prepared by Miller and Lents, LTD.

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


	Gross Acres		Net Acres

Developed		691,959		352,486
Undeveloped		1,198,824		612,669

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


	Operating statistics

We focus on lower-risk development drilling. Our drilling success rate was over 99 percent in 2004 and 99 percent in 2003. The following tables summarize domestic drilling activity by number and type of well for the periods indicated:


Number of Wells			Gross Wells		Net Wells

Development:
	Drilled
		2004		1,395		710
		2003		900		419
		2002		1,347		723
	Successful
		2004		1,384		706
		2003		891		414
		2002		1,334		714

Substantially all our natural gas production is currently being sold to Power at prevailing market prices. Because we currently have a low-risk drilling program in proven basins, the main component of risk that we manage is price risk. Exploration & Production has entered into derivative contracts with Power that hedge 286 BBtud in fixed price hedges (whole year) and 50 Bbtud in collars for January through March for projected 2005 domestic natural gas production. Power then enters into offsetting derivative contracts with unrelated third parties. 400 BBtud of our natural gas production in 2004 was hedged. Hedging decisions are made considering the overall Williams commodity risk exposure and are not executed independently by Exploration & Production; there are gas purchase hedging contracts executed on behalf of other Williams entities which taken as a net position may counteract Exploration & Production gas sales hedging derivatives.

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


	2004			2003			2002

Total net production sold (in Bcfe)		189.4			182.1			211.5
Average production costs including production taxes per thousand cubic feet of gas equivalent (Mcfe) produced	$	.88		$	.76		$	.58
Average sales price per Mcfe	$	4.48		$	3.87		$	2.03
Realized impact of hedging contracts [Gain (Loss)]	$	(1.32	)	$	(.51	)	$	1.20


	Acquisitions

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


	Environmental and other regulatory matters

Our Exploration & Production business is subject to various federal, state and local laws and regulations on taxation, the development, production and marketing of oil and gas, and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters. Such laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our oil and gas wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our reserves.

Our operations are subject to complex environmental laws and regulations adopted by the various jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil, or water, including responsibility for remedial costs. We could potentially discharge such materials into the environment in many ways including:


	•	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.


	Competition

The natural gas industry is highly competitive. We compete with other oil and gas concerns, including major and independent oil and gas companies in the development, production and marketing of natural gas. We compete in areas such as the acquisition of oil and gas properties and obtaining necessary equipment, supplies and services. We also compete in recruiting and retaining skilled employees.


	Ownership of property

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


	Other information

In 1993, Exploration & Production conveyed a net profits interest in certain of its properties to the Williams Coal Seam Gas Royalty Trust. Substantially all of the production attributable to the properties conveyed to the trust was from the Fruitland coal formation and constituted coal seam gas. We subsequently sold trust units to the public in an underwritten public offering and retained 3,568,791 trust units representing 36.8 percent of outstanding trust units. During 2000, we sold all of our trust units as part of a Section 29 tax credit transaction, in which we retained an option to repurchase the units. We registered the units with the SEC and had been repurchasing the units and reselling the units on the open market from time to time. In June 2003, we repurchased the remaining 2,408,791 trust units covered by the repurchase option. As of March 1, 2005, we own 995,791 trust units.


	International exploration and production interests

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

Midstream


	*Midstream overview*


	•	We own and operate gas gathering, treating and processing facilities within the western states of Wyoming, Colorado, and New Mexico and onshore and offshore in and around the Gulf Coast states of Texas, Louisiana, Mississippi, and Alabama.

	•	We operate and have ownership interests in various Venezuelan midstream energy assets.

	•	We own interests in and/or operate natural gas liquids transportation, fractionation and storage assets in central Kansas and southern Louisiana.

	•	We own and operate ethane cracking, olefin liquids extraction and olefin fractionation assets within Louisiana.

	•	We own an olefin liquids extraction plant and an olefin fractionation facility within Alberta, Canada.


	*Midstream details*

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

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

Our Canadian and Gulf Liquids olefin facilities have an exposure similar to our “Keep Whole” contracts. We are exposed to the spread between the price for natural gas and the products we produce. In the Gulf Coast, our feedstock for the ethane cracker is ethane and propane; as a result, we are exposed to the price spread between ethane and propane and ethylene and propylene.

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


	Domestic gathering and processing

Geographically, our Midstream natural gas assets are positioned to maximize commercial and operational synergies with our other assets. For example, most of our offshore gathering and processing assets attach and process or condition natural gas supplies delivered to the Transco pipeline. Also, our gathering and processing facilities in the San Juan Basin handle about 80 percent of our Exploration & Production group’s wellhead production in this basin. Several of our western gathering systems serve as critical sources of supply for Northwest Pipeline customers.

We own and/or operate domestic gas gathering and processing assets primarily within the western states of Wyoming, Colorado and New Mexico, and the onshore and offshore shelf and deepwater areas in and around the Gulf Coast states of Texas, Louisiana, Mississippi and Alabama. These assets consist of approximately 8,100 miles of gathering pipelines, nine processing plants (one partially owned) and six natural

gas treating plants with a combined daily inlet capacity in excess of 5.3 billion cubic feet per day. In addition to these natural gas assets, we own and operate three crude oil pipelines totaling approximately 270 miles with a capacity of more than 300,000 barrels per day. This includes our recently completed Mountaineer crude oil pipeline in the deepwater Gulf of Mexico that serves the Dominion Exploration & Production-operated Devils Tower field. See Gathering and processing — deepwater projects below.

Included in the natural gas assets listed above are the assets of Discovery Producer Services LLC and its subsidiary Discovery Gas Transmission Services LLC (Discovery). We own a 50 percent interest in Discovery and operate its facilities. Discovery’s assets include a cryogenic natural gas processing plant near Larose, Louisiana, a natural gas liquids fractionator plant near Paradis, Louisiana and an offshore natural gas gathering and transportation system.

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


	Gulf Coast petrochemical and olefins

We own a ⁵/12 interest in and are the operator for an ethane cracker at Geismar, Louisiana, with a total production capacity of 1.3 billion pounds per year of ethylene. During the fourth quarter of 2004, we closed on the sale of our interest in an associated ethane/ ethylene storage and transportation complex located in Choctaw, Louisiana. We continue to own a major ethane pipeline system in Louisiana.

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


	Venezuela

Our Venezuelan investments involve gas compression and gas processing and natural gas liquids fractionation operations. We own controlling interests in three gas compressor facilities which provide roughly 65 percent of the gas injections in eastern Venezuela. These facilities help stabilize the reservoir and enhance the recovery of crude oil by re-injecting natural gas at high pressures. We also own a 49.25 percent interest in two 400 MMcf/d natural gas liquids extraction plants, a 50,000 barrels per day natural gas liquids fractionation plant and associated storage and refrigeration facilities.

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


	Canada

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

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

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


	Other

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.


	Expansion projects


	Gathering and processing — Wyoming expansion

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

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

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


	*Gathering and processing — deepwater projects*

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

Our new floating production system and associated pipelines, Devils Tower, became operational on May 5, 2004. Initially built to serve Dominion Exploration & Production’s Devils Tower field, the floating production system is located in Mississippi Canyon Block 773, approximately 150 miles south-southwest of Mobile, Alabama. Located in 5,610 feet of water, it is the world’s deepest dry tree spar. The platform, which is operated by Dominion on our behalf, is capable of producing 110 MMcf/d of natural gas and 60 Mbbls/d of oil.

The Devils Tower project includes gas and oil pipelines. The 102-mile Canyon Chief gas line consists of 18-inch diameter pipe. The 117-mile Mountaineer oil pipeline is a combination of 18- and 20-inch diameter pipe. The gas is delivered into Transco’s pipeline, and processed at our Mobile Bay Plant to recover the natural gas liquids. The oil is transported to ChevronTexaco’s Empire Terminal in Plaquemines Parish, Louisiana.

Our 18-inch oil pipeline, Alpine, which became operational on December 14, 2003 is averaging approximately 17.6 Mbbls/d for the fourth quarter of 2004. The pipeline extends 96 miles from Garden Banks Block 668 in the central Gulf of Mexico to our shallow-water platform at Galveston Area Block A244. From this platform, the oil is delivered onshore through ExxonMobil’s Hoover Offshore Oil Pipeline System under a joint tariff agreement. This production is coming from the Gunnison field, which is located in 3,150 feet of

water and operated by Kerr-McGee Oil & Gas Corporation, a wholly-owned subsidiary of Kerr-McGee Corporation.

Since 1997, we have invested almost $1 billion in new midstream assets in the Gulf of Mexico. These facilities provide both onshore and offshore services through pipelines, platforms and processing plants. The new facilities could also attract incremental gas volumes to Transco’s pipeline system in the southeastern United States.


	Customers and operations

Our domestic gas gathering and processing customers are generally natural gas producers who have proved and/or producing natural gas fields in the areas surrounding our infrastructure. During 2004, these operations gathered and processed gas for approximately 200 gas gathering customers and 100 processing customers. Our top three gathering and processing customers accounted for about thirty percent (30%) of our domestic gathering revenue and processing gross margin. Our gathering and processing agreements are generally long-term agreements.

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

Our Venezuelan assets were constructed and are currently operated for the exclusive benefit of PDVSA. The significant contracts have a remaining term between 13 and 17 years and our revenues are based on a combination of fixed capital payments, throughput volumes, and, in the case of one of the gas compression facilities, a minimum throughput guarantee. During 2004, Venezuelan President Hugo Chavez successfully defeated a referendum vote calling for his removal from office. The internal political situation has enjoyed relative calm since the conclusion of the referendum. However, President Chavez has confirmed his public criticism of U.S. policy and has implemented unilateral changes to existing energy related contracts, indicating that a level of political risk still remains.


	Financial & operating statistics

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


	2004		2003		2002

Volumes(1):
Domestic Gathering (trillion British Thermal Units)(2)		1,252		1,272		1,308
Domestic Natural Gas Liquid Production (Mbbls/d)(3)		155		129		135
Crude Oil Gathering (Mbbls/d)(3)		83		68		24


(1)	Excludes volumes associated with partially owned assets that are not consolidated for financial reporting purposes.

(2)	Prior periods for Domestic Gathering have been restated to reflect the transfer of the jurisdictional assets to Transco.

(3)	Annual Average Mbbls/d


	Regulatory and environmental matters

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

Of the states where Midstream operates, currently only Kansas and Texas actively regulate gathering activities. Those states regulate gathering primarily through complaint mechanisms under which the state commission may resolve disputes involving an individual gathering arrangement. Although gathering facilities located offshore are not subject to the NGA, some controversy exists as to how the FERC should determine whether offshore facilities function as gathering. These issues are currently before the FERC. Most gathering facilities offshore are subject to the OCSLA, which provides in part that outer continental shelf pipelines “must provide open and nondiscriminatory access to both owner and non-owner shippers.”

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

Our remaining Midstream Canadian assets are regulated by the Alberta Energy & Utilities Board (AEUB) and Alberta Environment. The regulatory system for the Alberta oil and gas industry incorporates a large measure of self-regulation, providing that licensed operators are held responsible for ensuring that their operations are conducted in accordance with all provincial regulatory requirements. For situations in which non-compliance with the applicable regulations is at issue, the AEUB and Alberta Environment have implemented an enforcement process with escalating consequences.


	Competition

The gathering and processing business is a regional business with varying competitive factors in each basin. Our gathering and processing business competes with other midstream companies, interstate and intrastate pipelines, master limited partnerships (MLP), producers and independent gatherers and processors. We primarily compete with five to ten companies across all basins in which we provide services. Our focus is to provide our customers with the most reliable and consistent service at a competitive price.

Numerous factors impact any given customer’s choice of a gathering or processing services provider, including rate, location, term, timeliness of well connections, pressure obligations and the willingness of the provider to process for either a fee or for liquids taken in-kind. Our gathering and processing services are generally covered by long-term contracts with applicable acreage or reserve dedications. The active drilling programs near our relatively large positions in the San Juan Basin, Wyoming area and Gulf Coast Region indicate that demand for future gathering and processing infrastructure and services should continue.


	Ownership of property

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

Other

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

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

Additional business segment information

Our ongoing business segments are accounted for as continuing operations in the accompanying financial statements and notes to financial statements included in Part II.

Operations related to certain assets in “Discontinued Operations” sold in 2002, 2003 and 2004 have been reclassified from their traditional business segment to “Discontinued Operations” in the accompanying financial statements and notes to financial statements included in Part II.

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

Our principal sources of cash are from external financings, dividends and advances from our subsidiaries, investments, payments by subsidiaries for services rendered, interest payments from subsidiaries on cash advances and net proceeds from asset sales. The amount of dividends available to us from subsidiaries largely depends upon each subsidiary’s earnings and operating capital requirements. The terms of many of our subsidiaries’ borrowing arrangements limit the transfer of funds to our corporate parent.

We believe that we have adequate sources and availability of raw materials and commodities for existing and anticipated business needs. In support of our energy commodity activities, primarily conducted through Power, we are required by counterparties to provide various forms of credit support such as margin, adequate assurance amounts and pre-payments for gas supplies. Our pipeline systems are all regulated in various ways resulting in the financial return on the investments made in the systems being limited to standards permitted by the regulatory agencies. Each of the pipeline systems has ongoing capital requirements for efficiency and mandatory improvements, with expansion opportunities also necessitating periodic capital outlays.

ENVIRONMENTAL MATTERS

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

EMPLOYEES

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

FORWARD LOOKING STATEMENTS/ RISK FACTORS AND CAUTIONARY STATEMENT

FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF

THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

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

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

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


	•	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;

	•	development drilling potential;

	•	cash flow from operations; 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.

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

RISK FACTORS

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

Risks related to our business


	*Our risk measurement and hedging activities might not prevent losses.*

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

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

To lower our financial exposure related to commodity price and market fluctuations, we have entered into contracts to hedge certain risks associated with our assets and operations, including our long-term tolling agreements. In these hedging activities, we have used fixed-price, forward, physical purchase and sales contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges, as well as long-term structured transactions when feasible. Substantial declines in market liquidity, however, as well as our current credit rating, and termination of existing positions (due for example to credit concerns) have greatly limited our ability to hedge risks identified and have caused previously hedged positions to become unhedged. To the extent we have unhedged positions, fluctuating commodity prices could cause our net revenues and net income to be volatile.

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

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

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


	•	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.


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

Our revenues, operating results, 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;

	•	terrorist attacks on production or transportation assets;

	•	weather conditions;

	•	the level of consumer demand;

	•	the price and availability of other types of fuels;

	•	the availability of pipeline capacity;

	•	the price and level of foreign imports;

	•	domestic and foreign governmental regulations and taxes;

	•	volatility in the natural gas markets;

	•	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.


	*We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets.*

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.


	*Our operating results might fluctuate on a seasonal and quarterly basis.*

Revenues from our businesses, including gas transmission and the sale of electric power, can have seasonal characteristics. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, demand for power peaks during the winter. In addition, demand for gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and pipeline

systems and the terms of our power sale agreements and gas transmission arrangements relative to demand created by unusual weather patterns.


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

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

Operations in foreign countries also can present currency exchange rate and convertibility, inflation and repatriation risk. In certain conditions under which we develop or acquire projects, or make investments, economic and monetary conditions and other factors could affect our ability to convert our earnings denominated in foreign currencies. In addition, risk from fluctuations in currency exchange rates can arise when our foreign subsidiaries expend or borrow funds in one type of currency but receive revenue in another. In such cases, an adverse change in exchange rates can reduce our ability to meet expenses, including debt service obligations. Foreign currency risk can also arise when the revenues received by our foreign subsidiaries are not in U.S. dollars. In such cases, a strengthening of the U.S. dollar could reduce the amount of cash and income we receive from these foreign subsidiaries. While we believe we have hedges and contracts in place to mitigate our most significant foreign currency exchange risks, our hedges might not be sufficient or we might have some exposures that are not hedged which could result in losses or volatility in our revenues.


	*Our debt agreements impose restrictions on us that may adversely affect our ability to operate our business.*

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

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

Risks related to the regulation of our businesses


	Our businesses are subject to complex government regulations. The operation of our businesses might be adversely affected by changes in these regulations or in their interpretation or implementation.

Existing regulations might be revised or reinterpreted, new laws and regulations might be adopted or become applicable to us or our facilities, and future changes in laws and regulations might have a detrimental effect on our business. Over the past few years, certain restructured energy markets have experienced supply problems and price volatility. In some of these markets, including California, proposals have been made by governmental agencies and other interested parties to re-regulate areas of these markets which have previously been deregulated. Various forms of market controls and limitations including price caps and bid caps have already been implemented and new controls and market restructuring proposals are in various stages of development, consideration and implementation. We cannot assure you that changes in market structure and regulation will not adversely affect our business. We cannot assure you that other proposals to re-regulate will not be made or that legislative or other attention to the electric power restructuring process will not cause the deregulation process to be delayed or reversed.


	Our revenues might decrease if we are unable to gain adequate, reliable and affordable access to transmission and distribution assets due to the FERC and regional regulation of wholesale market transactions for electricity and gas.

We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity and natural gas we buy and sell in the wholesale market. If transmission is disrupted, if capacity is inadequate, or if credit requirements or rates of such utilities or energy companies are increased, our ability to sell and deliver products might be hindered. The FERC has issued power transmission regulations that require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, some companies have failed to provide fair and equal access to their transmission systems or have not provided sufficient transmission capacity to enable other companies to transmit electric power. We cannot predict whether and to what extent the industry will comply with these initiatives, or whether the regulations will fully accomplish the FERC’s objectives.

In addition, the independent system operators who oversee the transmission systems in regional power markets, such as California, have in the past been authorized to impose, and might continue to impose, price limitations and other mechanisms to address volatility in the power markets. These types of price limitations and other mechanisms might adversely impact the profitability of our wholesale power marketing and trading. Given the extreme volatility and lack of meaningful long-term price history in many of these markets and the imposition of price limitations by regulators, independent system operators or other marker operators, we can offer no assurance that we will be able to operate profitably in all wholesale power markets.


	Our gas sales, transmission, and storage operations are subject to government regulations and rate proceedings that could have an adverse impact on our ability to recover the costs of operating our pipeline facilities.

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.


	The different regional power markets in which we compete or will compete in the future have changing regulatory structures, which could affect our growth and performance in these regions.

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

Risks related to legal proceedings and governmental investigations

Public and regulatory scrutiny of the energy industry and of the capital markets has resulted in increased regulation being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations and court proceedings, including a DOJ investigation and private class actions and shareholder lawsuits in which we are a named defendant.

Such inquiries, investigations and court proceedings are ongoing and continue to adversely affect our business as a whole. We might see these adverse effects continue as a result of the uncertainty of these ongoing inquiries and proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current legal proceedings against us arising out of the operation of our Power business, our former telecommunications subsidiary, or other matters related to our ongoing business include environmental matters, disputes over gas measurement and royalty payments, ERISA litigation, shareholder class action suits, regulatory appeals and similar matters. Any or all of these matters might result in adverse decisions against us. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

Risks affecting our strategy and financing needs


	*Developments affecting the wholesale power and energy trading industry sector have reduced market activity and liquidity and might continue to adversely affect our results of operations.*

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

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


	*Because we no longer maintain investment grade credit ratings, our counterparties have required us to provide higher amounts of credit support which raises our cost of doing business.*

Our transactions in each of our businesses require greater credit assurances, both to be given from, and received by, us to satisfy credit support requirements. Additionally, certain market disruptions or a further downgrade of our credit rating might further increase our cost of borrowing or further impair our ability to access one or any of the capital markets. Such disruptions could include:


	•	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.


	*Despite our restructuring efforts, we may not attain investment grade ratings.*

Credit rating agencies perform independent analysis when assigning credit ratings. Given the significant changes in capital markets and the energy industry over the last few years, credit rating agencies continue to review the criteria for attaining investment grade ratings and make changes to those criteria from time to time. Our goal is to attain investment grade ratios. However, there is no guarantee that the credit rating agencies will assign us investment grade ratings even if we meet or exceed their criteria for investment grade ratios.

Risks related to outsourcing of non-core support services


	*Institutional knowledge represented by our former employees now employed by our outsourcing service provider might not be adequately preserved.*

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


	*Failure of the outsourcing relationship might negatively impact our ability to conduct our business.*

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


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

Certain information technology application development, human resources, and helpdesk services that are currently provided by an outsourcer will be relocated to service centers operated by our outsourcing provider outside of the United States during 2005. The economic and political conditions in certain countries from which our outsourcing providers may provide services to us present similar risks of business operations located outside of the United States, including risks of interruption of business, war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States.

Risks related to environmental matters


	We could incur material losses if we are held liable for the environmental condition of any of our assets or divested assets, which could include losses that exceed our current expectations.

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

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


	Environmental regulation and liability relating to our business will be subject to environmental legislation in all jurisdictions in which it operates, and any changes in such legislation could negatively affect our results of operations.

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

Compliance with environmental legislation will require significant expenditures, including expenditures for compliance with the Clean Air Act and similar legislation, for clean up costs and damages arising out of contaminated properties, and for failure to comply with environmental legislation and regulations which might result in the imposition of fines and penalties. The steps we take to bring certain of our facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.

Further, our regulatory rate structure and our contracts with clients might not necessarily allow us to recover capital costs we incur to comply with new environmental regulations. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for certain development projects. If there is a delay in obtaining any required environmental regulatory approvals or if we fail to obtain and comply with them, the operation of our facilities could be prevented or become subject to additional costs. Should we fail to comply with all applicable environmental laws, we might be subject to penalties and fines imposed against us by regulatory authorities. Although we do not expect that the costs of complying with current environmental legislation will have a material adverse effect on our financial condition or results of

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

Risks relating to accounting standards


	Potential changes in accounting standards might cause us to revise our financial results and disclosure in the future, which might change the way analysts measure our business or financial performance.

Accounting irregularities discovered in the past few years in various industries have forced regulators and legislators to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent auditors and retirement plan practices. Because it is still unclear what laws or regulations will ultimately develop, we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically.

In addition, the Financial Accounting Standards Board (FASB) or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets and liabilities.

Risks relating to our industry


	*The long-term financial condition of our natural gas transmission and midstream businesses are dependent on the continued availability of natural gas reserves.*

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 drilling, production, gathering, processing and transporting activities involve numerous risks that might result in accidents and other operating risks and costs.*

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

significant or do considerable harm to people or property. Certain segments of our pipelines run through HCAs. An event such as those described above in a HCA not only could cause considerable harm to people or property, but could have a material adverse effect on our financial position and results of operations, particularly if the event is not fully covered by insurance.

Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers. For example, the 26 inch segment of Northwest Pipeline from Sumas to Washougal, Washington was idled in 2003 after a line break associated with stress corrosion cracking (SCC). SCC is caused by a specific combination of stress and exposure to environmental factors such as soil acidity, moisture, and electro chemical properties that occurs in older pipelines. This type of corrosion cracking is a very complex technical phenomenon and, while the industry is making progress in developing methods to predict and identify SCC, there are still many unknowns.

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

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

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


	Estimating reserves and future net revenues involves uncertainties and negative revisions to reserve estimates, and oil and gas price declines may lead to impairment of oil and gas assets.

Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The process relies on interpretations of available geological, geophysical, engineering and production data. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of developmental expenditures, including many factors beyond the control of the producer. The reserve data included in this Form 10-K represent estimates. In addition, the estimates of future net revenues from our proved reserves and the present value of such estimates are based upon certain assumptions about future production levels, prices and costs that may not prove to be correct over time.

Quantities of proved reserves are estimated based on economic conditions in existence during the period of assessment. Lower oil and gas prices may have the impact of shortening the economic lives of certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, which reduces proved property reserve estimates.

If negative revisions in the estimated quantities of proved reserves were to occur, it would have the effect of increasing the rates of depreciation, depletion and amortization on the affected properties, which would decrease earnings or result in losses through higher depreciation, depletion and amortization expense. The

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

Other risks


	*The threat of terrorist activities and the potential for continued military and other actions could adversely affect our business.*

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.


	*Historic performance of our exploration and production business is no guarantee of future performance.*

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


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

Our assets and operations, especially those located offshore, can be adversely affected by hurricanes, earthquakes, tornadoes and other natural phenomena and weather conditions including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations.

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

See Note 18 of our Notes to Consolidated Financial Statements for amounts of revenues during the last three fiscal years from external customers attributable to the United States and all foreign countries. See Note 18 of our Notes to Consolidated Financial Statements for information relating to long-lived assets during the last two fiscal years, other than financial instruments, long-term customer relationships of a financial institution, mortgage and other servicing rights and deferred policy acquisition costs, located in the United States and all foreign countries.


Item 3.	*Legal Proceedings*

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


Item 4.	*Submission of Matters to a Vote of Security Holders*

None.

Item 4A. Executive Officers of the Registrant

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


Alan S. Armstrong		Senior Vice President, Midstream Age: 42 Position held since February 2002.
		From 1999 to February 2002, Mr. Armstrong was Vice President, Gathering and Processing for Midstream. From 1998 to 1999 he was Vice President, Commercial Development for Midstream.
James J. Bender		Senior Vice President and General Counsel Age 48 Position held since December 16, 2002.
		Prior to joining us, Mr. Bender was Senior Vice President and General Counsel with NRG Energy, Inc., a position held since June 2000, prior to which he was Vice President, General Counsel and Secretary of NRG Energy Inc. since June 1997. NRG Energy, Inc. filed a voluntary bankruptcy petition during 2003 and its plan of reorganization was approved in December 2003.
Donald R. Chappel		Senior Vice President and Chief Financial Officer Age: 53 Position held since April 16, 2003.
		Prior to joining us, Mr. Chappel during 2000 founded and served as chief executive officer of a development business in Chicago, Illinois through April, 2003 when he joined us. Mr. Chappel joined Waste Management, Inc. in 1987 and held various financial, administrative and operational leadership positions, including twice serving as chief financial officer, during 1997 and 1998 and most recently during 1999 through February 2000.
Ralph A. Hill		Senior Vice President, Exploration and Production Age: 45 Position held since December 1998.
		Mr. Hill was vice president of the exploration and production unit from 1993 to 1998 as well as Senior Vice President Petroleum Services from 1998 to 2003.
William E. Hobbs		Senior Vice President, Power Age: 45 Position held since October 2002
		From February 2000 to October 2002, Mr. Hobbs was President and Chief Executive Officer of Williams Energy Marketing & Trading. From 1997 to February 2000, he served as a Vice President of various Williams subsidiaries.
Michael P. Johnson, Sr.		Senior Vice President and Chief Administrative Officer Age: 57 Position held since May 2004.
		Mr. Johnson was named our Senior Vice President of Human Resources and Administration in April 1999. Prior to joining us in December 1998, he held officer level positions, such as Vice President of Human Resources, Vice President for Corporate People Strategies, and Vice President Human Resource Services, for Amoco Corporation from 1991 to 1998.
Steven J. Malcolm		Chairman of the Board, Chief Executive Officer and President Age: 56 Position held since September 21, 2001.
		Mr. Malcolm was elected Chief Executive Officer of Williams in January 2002 and Chairman of the Board in May 2002. He was elected President and Chief Operating Officer in September 2001. Prior to that, he was our Executive Vice President from May 2001, President and Chief Executive Officer of our subsidiary Williams Energy Services, LLC, since December 1998 and the Senior Vice President and General Manager of our subsidiary, Williams Field Services Company, since November 1994.


Phillip D. Wright		Senior Vice President, Gas Pipeline Age: 49 Position held since January 2005.
		From October 2002 to January 2005, Mr. Wright served as Chief Restructuring Officer. From September 2001 to October 2002, Mr. Wright served as President and Chief Executive Officer of our subsidiary Williams Energy Services. From 1996 until September 2001, he was Senior Vice President, Enterprise Development and Planning for our energy services group. Mr. Wright has held various positions with us since 1989.

PART II


Item 5.	*Market for Registrant’s Common Equity and Related Stockholder Matters*

Our common stock is listed on the New York Stock Exchange and Pacific Stock Exchanges under the symbol “WMB.” At the close of business on February 28, 2005, we had approximately 13,234 holders of record of our common stock. The high and low closing sales price ranges (New York Stock Exchange composite transactions) and dividends declared by quarter for each of the past two years are as follows:


	2004						2003

Quarter	High		Low		Dividend		High		Low		Dividend

1st	$	11.30	$	8.75	$	.01	$	4.74	$	2.60	$	.01
2nd	$	12.23	$	9.89	$	.01	$	8.77	$	4.87	$	.01
3rd	$	12.51	$	11.45	$	.01	$	9.42	$	6.20	$	.01
4th	$	17.10	$	12.35	$	.05	$	10.62	$	8.94	$	.01

Some of our subsidiaries’ borrowing arrangements limit the transfer of funds to us. These terms have not impeded, nor are they expected to impede, our ability to pay dividends. However, until January 20, 2005, the credit agreements underlying our two unsecured revolving credit facilities totaling $500 million prohibited us from paying quarterly cash dividends on our common stock in excess of $0.05 per share. On January 20, 2005, these facilities were terminated and replaced with two new facilities. As part of the transaction, the dividend restriction, along with most of the other restrictive covenants, was removed from the new credit agreements.


Item 6.	*Selected Financial Data*

The following financial data as of December 31, 2004 and 2003 and for the three years ended December 31, 2004 are an integral part of, and should be read in conjunction with, the consolidated financial statements and notes thereto. All other amounts have been prepared from our financial records. Certain amounts below have been restated or reclassified. See Note 1 of Notes to Consolidated Financial Statements in Item 8 for discussion of changes in 2004, 2003 and 2002. Results for the years 2001 and 2000 also include amounts related to the discontinued operations of Williams Communications Group, our previously owned communications subsidiary (WilTel). Information concerning significant trends in the financial condition and results of operations is contained in Management’s Discussion & Analysis of Financial Condition and Results of Operations of this report.


		2004		2003			2002			2001			2000

		(Millions, except per-share amounts)
Revenues(1)		$	12,461.3	$	16,651.0		$	3,434.5		$	4,899.5		$	4,859.2
Income (loss) from continuing operations(2)			93.2		(57.5	)		(618.4	)		640.5			666.5
Income (loss) from discontinued operations(3)			70.5		326.6			(136.3	)		(1,118.2	)		(142.2	)
Cumulative effect of change in accounting principles(4)			—		(761.3	)		—			—			—
Diluted earnings (loss) per common share:
	Income (loss) from continuing operations		.18		(.17	)		(1.37	)		1.28			1.49
	Income (loss) from discontinued operations		.13		.63			(.26	)		(2.23	)		(.32	)
	Cumulative effect of change in accounting principles		—		(1.47	)		—			—			—
Total assets at December 31			23,993.0		27,021.8			34,988.5			38,614.2			34,776.6
Short-term notes payable and long-term debt due within one year			250.1		938.5			2,077.1			2,510.4			3,193.2
Long-term debt at December 31			7,711.9		11,039.8			11,075.7			8,285.0			6,316.8
Preferred interests in consolidated subsidiaries at December 31			—		—			—			976.4			877.9
Williams obligated mandatorily redeemable preferred securities of Trust at December 31			—		—			—			—			189.9
Stockholders’ equity at December 31(5)			4,955.9		4,102.1			5,049.0			6,044.0			5,892.0
Cash dividends per common share			.08		.04			.42			.68			.60


(1)	As discussed in Note 1 of Notes to Consolidated Financial Statements, the adoption of Emerging Issues Task Force Issue No. 02-3 (EITF 02-3) requires that revenues and costs of sale from non-derivative contracts and certain physically settled derivative contracts be reported on a gross basis. Prior to the adoption on January 1, 2003, these revenues were presented net of costs. As permitted by EITF 02-3, prior year amounts have not been restated. Also, see Note 1 of Notes to Consolidated Financial Statements for discussion of revenue recognized in 2003 related to the correction of prior period items.

(2)	See Note 4 of Notes to Consolidated Financial Statements for discussion of asset sales, impairments and other accruals in 2004, 2003 and 2002.

(3)	See Note 2 of Notes to Consolidated Financial Statements for the discussion of the 2004, 2003 and 2002 income (loss) from discontinued operations. Results for the years 2001 and 2000 also include amounts related to the discontinued operations of WilTel.

(4)	The 2003 cumulative effect of change in accounting principles includes a $762.5 million charge related to the adoption of EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” slightly offset by $1.2 million related to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations.” The $762.5 million charge primarily consists of the fair value of power tolling, load serving, transportation and storage contracts. These contracts did not meet the definition of a derivative and, therefore, are no longer reported at fair value.

(5)	Stockholders’ equity for 2001 includes the January 2001 common stock issuance, the issuance of common stock for the Barrett acquisition and the impact of the WilTel spinoff.


Item 7.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*


	*Overview of 2004*

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

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


	•	Completion of planned asset sales, which resulted in proceeds of approximately $877.8 million.

	•	Replacement of our cash-collateralized letter of credit and revolver facility with facilities that do not encumber cash.

	•	Reduction of approximately $4 billion of debt through scheduled maturities and early redemptions, including an exchange offer for our FELINE PACS units.

	•	Reduction of risk and liquidity requirements of the Power segment.

	•	Reduction of approximately $33 million in our combined selling, general and administrative (SG&A) and general corporate expenses.

	•	On June 1, 2004, we announced an agreement with International Business Machines Corporation (IBM) to aid us in transforming and managing certain areas of our accounting, finance and human resources processes. Under the agreement, IBM will also manage key aspects of our information technology, including enterprise wide infrastructure and application development. The 7¹/2 year agreement began July 1, 2004 and is expected to reduce costs in these areas while maintaining a high quality of service.


	*Current liquidity*

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


	*Power business*

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


	•	the cash flow expected to be generated by the business (Power has contracts in place expected to generate cash in amounts that substantially cover its obligations through 2010);

	•	the negative effect of depressed wholesale power markets on the marketability of the Power segment; and

	•	our progress over the last two years in reducing the risk and increasing the certainty of cash flows from long-term power contracts.

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


	*Outlook for 2005*

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

Our plan for 2005 includes the following objectives:


	•	increase focus and disciplined EVA®-based investments in natural gas businesses;

	•	continue to steadily improve credit ratios and ratings with the goal of achieving investment grade ratios;

	•	continue to reduce risk and liquidity requirements while maximizing cash flow in the Power segment;

	•	maintain liquidity from cash and revolving credit facilities of at least $1 billion; and

	•	generate sustainable growth in EVA® and shareholder value.

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

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


	•	lower than expected levels of cash flow from operations;

	•	volatility of commodity prices;

	•	decreased drilling success at Exploration & Production;

	•	exposure associated with our efforts to resolve regulatory and litigation issues (see Note 15 of Notes to Consolidated Financial Statements); and

	•	general economic and industry downturn.

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

Critical accounting policies & estimates

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


	*Revenue recognition — derivatives*

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

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

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


	*Oil and gas producing activities*

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


	•	An increase (decrease) in estimated proved oil and gas reserves can reduce (increase) our unit of production depreciation, depletion and amortization rates.

	•	Changes in oil and gas reserves and forward market prices both impact projected future cash flows from our oil and gas properties. These projected future cash flows are used:


	o	to estimate the fair value of oil and gas properties for purposes of assessing them for impairment; and

	o	to estimate the fair value of the Exploration & Production reporting unit for purposes of assessing its goodwill for impairment.


	•	Certain estimated reserves are used as collateral to secure financing.

The process of estimating natural gas and oil reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. After being estimated internally, 99 percent of our reserve estimates are either audited or prepared by independent experts. The data may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates could occur from time to time. A reasonably likely revision of our reserve estimates is not expected to result in an impairment of our oil and gas properties or goodwill. However, reserve estimate revisions would impact our depreciation and depletion expense prospectively. For example, a change of approximately 10 percent in oil and gas reserves for each basin would change our annual depreciation, depletion and amortization expense between approximately $16 million and $22 million. The actual impact would depend on the specific basins impacted and whether the change resulted from proved developed, proved undeveloped or a combination of these reserve categories.

Forward market prices include estimates of prices for periods that extend beyond those with quoted market prices. This forward market price information is consistent with that generally used in evaluating drilling decisions and acquisition plans. These market prices for future periods impact the production economics underlying oil and gas reserve estimates. The prices of natural gas and oil are volatile and change from period to period thus impacting our estimates. A reasonably likely unfavorable change in the forward price curve is not expected to result in an impairment of our oil and gas properties or goodwill.


	*Contingent liabilities*

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which new or different facts or information become known or

circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates, and advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, it is possible that our assumptions and estimates in these matters will change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period. See Note 15 of Notes to Consolidated Financial Statements.


	*Valuation of deferred tax assets and tax contingencies*

We have deferred tax assets resulting from certain investments and businesses that have a tax basis in excess of the book basis and from tax carry-forwards generated in the current and prior years. We evaluate whether we will ultimately realize these tax benefits and establish a valuation allowance for those that may not be realizable. This evaluation considers tax planning strategies, including assumptions about the availability and character of future taxable income. At December 31, 2004, we have $780 million of deferred tax assets for which a $62 million valuation allowance has been established. When assessing the need for a valuation allowance, we considered forecasts of future company performance, the estimated impact of potential asset dispositions, and our ability and intent to execute tax planning strategies to utilize tax carryovers. Based on our projections, we believe that it is probable that we can utilize our year-end 2004 federal tax net operating loss carryovers and capital loss carryovers prior to their expiration. We do not expect to be able to utilize $21 million, or approximately $8 million of tax benefit, of the charitable contribution carryovers expiring in 2005. The remaining $43 million of charitable contribution carryovers are expected to be utilized prior to their expiration. We also do not expect to be able to utilize $54 million of foreign deferred tax assets related to carryovers. See Note 5 of Notes to Consolidated Financial Statements for additional information regarding the tax carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by potential changes in jurisdictional income tax laws and the circumstances surrounding the actual realization of related tax assets.

We frequently face challenges from domestic and foreign tax authorities regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various filing positions, we record a liability for probable tax contingencies. The ultimate disposition of these contingencies could have a material impact on net cash flows. To the extent we were to prevail in matters for which accruals have been established or were required to pay amounts in excess of our accrued liability, our effective tax rate in a given financial statement period may be materially impacted.


	*Impairment of long-lived assets and investments*

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


	•	the probability that we would sell an asset or continue to hold and use it;

	•	undiscounted future cash flows if a long-lived asset is held for use;

	•	estimated fair value of the asset;

	•	estimated sales proceeds if an asset is sold;

	•	form and timing of the asset disposition;

	•	counterparty performance considerations under contracted sales transactions; and

	•	for investments that are impaired, whether the impairment is other than temporary.

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


	•	varying terms of renegotiated contracts;

	•	commodity pricing;

	•	probability weighting of different scenarios; and

	•	estimated sales proceeds if the assets were sold.

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

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


	•	commodity pricing;

	•	probability weighting of the different scenarios; and

	•	range of estimated sales proceeds, salvage value and future cash flows.

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


	*Pension and postretirement obligations*

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


		Benefit Expense						Benefit Obligation

		One-Percentage-			One-Percentage-			One-Percentage-			One-Percentage-
		Point Increase			Point Decrease			Point Increase			Point Decrease

		(Millions)
Pension benefits:
	Discount rate	$	(14	)	$	15		$	(125	)	$	146
	Expected long-term rate of return on plan assets		(8	)		8			—			—
	Rate of compensation increase		3			(2	)		11			(11	)
Other postretirement benefits:
	Discount rate		(1	)		5			(48	)		58
	Expected long-term rate of return on plan assets		(2	)		2			—			—
	Assumed health care cost trend rate		8			(3	)		52			(41	)

The expected long-term rates of return on plan assets are determined by combining a review of historical returns realized within the portfolio, the investment strategy included in the plans’ Investment Policy Statement, and the capital market projections provided by our independent investment consultant for the asset classifications in which the portfolio is invested as well as the target weightings of each asset classification. These rates are impacted by changes in general market conditions, but because they are long-term in nature, short-term market swings do not significantly impact the rates. Changes to our target asset allocation would also impact these rates.

The discount rates are used to discount future benefit obligations to today’s dollars. Decreases in this rate cause the obligation and related expense to increase. The discount rates for our pension and other postretirement benefit plans were determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 7 of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions which affect interest rates on long-term high quality corporate bonds.

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

The assumed health care cost trend rates used by the actuaries are based on our actual historical cost rates and then adjusted for expected changes in the health care industry.


	*TAPS Quality Bank*

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

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


	*Recent accounting standards*

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

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

General

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

Unless indicated otherwise, the following discussion and analysis of results of operations, financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II Item 8 of this document.

Results of operations


	*Consolidated overview*

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


		Years Ended December 31,

					% Change						% Change
					from						from
		2004			2003(1)			2003			2002(1)			2002

		(Millions)						(Millions)						(Millions)
Revenues		$	12,461.3			-25	%	$	16,651.0			NM		$	3,434.5
Costs and expenses:
	Costs and operating expenses		10,751.7			+28	%		15,004.3			NM			1,987.7
	Selling, general and administrative expenses		355.5			+16	%		421.3			+27	%		575.6
	Other (income) expense — net		(51.6	)		+142	%		(21.3	)		NM			240.4
	General corporate expenses		119.8			-38	%		87.0			+39	%		142.8

	Total costs and expenses		11,175.4			+28	%		15,491.3			NM			2,946.5
Operating income			1,285.9			+11	%		1,159.7			+138	%		488.0
Interest accrued — net			(827.7	)		+34	%		(1,248.0	)		-9	%		(1,141.9	)
Interest rate swap loss			(5.0	)		-127	%		(2.2	)		+98	%		(124.2	)
Investing income (loss)			48.0			-34	%		73.2			NM			(113.1	)
Early debt retirement costs			(282.1	)		NM			(66.8	)		NM			—
Minority interest in income and preferred returns of consolidated subsidiaries			(21.4	)		-10	%		(19.4	)		+54	%		(41.8	)
Other income — net			26.8			-34	%		40.7			+67	%		24.3

Income (loss) from continuing operations before income taxes and cumulative effect of change in accounting principles			224.5			NM			(62.8	)		+93	%		(908.7	)
Provision (benefit) for income taxes			131.3			NM			(5.3	)		-98	%		(290.3	)

Income (loss) from continuing operations			93.2			NM			(57.5	)		+91	%		(618.4	)
Income (loss) from discontinued operations			70.5			-78	%		326.6			NM			(136.3	)

Income (loss) before cumulative effect of change in accounting principles			163.7			-39	%		269.1			NM			(754.7	)
Cumulative effect of change in accounting principles			—			+100	%		(761.3	)		NM			—

Net income (loss)			163.7			NM			(492.2	)		+35	%		(754.7	)

Preferred stock dividends			—			+100	%		29.5			+67	%		90.1

Income (loss) applicable to common stock		$	163.7			NM		$	(521.7	)		+38	%	$	(844.8	)


(1)	+ = Favorable Change; — = Unfavorable Change; NM = A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.


	2004 vs. 2003

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

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

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

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


	•	$93.6 million income from an insurance arbitration award for Gulf Liquids, included in the Midstream segment;

	•	$16.2 million of gains from the sale of Exploration & Production’s securities, invested in a coal seam royalty trust, that were purchased for resale;

	•	a $9.5 million gain on the sale of Louisiana olefins assets in the Midstream segment;

	•	a $15.4 million loss provision related to an ownership dispute on prior period production included in the Exploration & Production segment;

	•	an $11.8 million environmental expense accrual related to the Augusta refinery facility, included in the Other segment; and

	•	a $9 million write-off of previously-capitalized costs on an idled segment of Northwest Pipeline’s system included in the Gas Pipeline segment.

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


	•	a $188 million gain from the sale of a Power contract;

	•	$96.7 million in net gains from the sale of Exploration & Production’s interests in certain natural gas properties in the San Juan basin;

	•	a $16.2 million gain from Midstream’s sale of the wholesale propane business;

	•	a $12.2 million gain on foreign currency exchange at Power;

	•	a $9.2 million gain on sale of blending assets at the Other segment;

	•	$7.2 million of income at Transcontinental Gas Pipe Line Corporation (Transco) due to a partial reduction of accrued liabilities for claims associated with certain producers as a result of settlements and court rulings included in the Gas Pipeline segment;

	•	a $108.7 million impairment on Gulf Liquids, included in the Midstream segment;

	•	a $45 million goodwill impairment at Power;

	•	a $44.1 million impairment of the Hazelton generation plant at Power;

	•	a $25.6 million charge at Northwest Pipeline to write-off capitalized software development costs for a service delivery system included in the Gas Pipeline segment;

	•	a $20 million charge related to a settlement by Power with the Commodity Futures Trading Commission (CFTC) (see Note 15 of Notes to Consolidated Financial Statements);


	•	a $19.5 million expense accrual at Power related to an adjustment of California rate refund and other related accruals; and

	•	a $7.2 million impairment of the Aspen project at the Other segment.

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

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


	•	$206 million lower interest expense and fees at Exploration & Production, due primarily to the May 2003 prepayment of a secured note payable of Williams Production RMT Company (the RMT note);

	•	a $164 million decrease reflecting lower average borrowing levels;

	•	$46 million lower amortization expense related to deferred debt issuance costs, primarily due to the reduction of debt;

	•	a $24 million decrease reflecting lower average interest rates on long-term debt;

	•	the absence in 2004 of $14 million of interest expense at Power related to a FERC ruling in 2003;

	•	the absence in 2004 of $10 million of interest expense related to a petroleum pricing dispute in 2003; and

	•	a $35 million decrease in capitalized interest due primarily to completion of certain Midstream projects in the Gulf Coast region.

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

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

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

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


	•	the $153 million of charges to increase our accrued liability associated with certain Quality Bank litigation matters (see Note 15);

	•	the absence in 2004 of approximately $108 million of income (net of losses) from discontinued operations in 2003 of Canadian liquids, Williams Energy Partners, Bio-energy facilities, Raton Basin and Hugoton Embayment natural gas exploration and production properties, Texas Gas, Midsouth refinery and related assets and Williams travel centers; and


	•	a decrease of approximately $50 million in income from the Canadian straddle plants and Alaska refining, retail and pipeline operations, which were sold in 2004.

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

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


	•	$463.4 million of gains on sales of assets;

	•	$176.1 million of impairments of assets; and

	•	$9.6 million of loss on sale of assets.

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

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

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


	2003 vs. 2002

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

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

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

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

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


	•	$244.6 million of impairment charges, loss accruals, and write-offs within Power, including a partial impairment of goodwill;

	•	$78.2 million of impairment charges related to Midstream’s Canadian olefin assets; and

	•	$141.7 million in net gains from the sale of Exploration & Production’s interests in natural gas properties.

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

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


	•	$48.1 million higher interest expense and fees primarily related to the RMT note payable, which was prepaid in May 2003;

	•	an $18.2 million increase in capitalized interest, which offsets interest accrued, due primarily to Midstream’s projects in the Gulf Coast Region;

	•	$21 million higher amortization expense related to deferred debt issuance costs including a $14.5 million write-off of accelerated amortization of costs from the termination of a revolving credit agreement in June 2003;

	•	a $43 million increase reflecting higher average interest rates on long-term debt;

	•	a $15 million decrease reflecting lower average borrowing levels; and

	•	$14 million of interest expense at Power as a result of certain 2003 FERC proceedings.

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

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


	•	the absence in 2003 of a $268.7 million loss provision relating to the estimated recoverability of receivables from WilTel;

	•	$56.1 million higher interest income due primarily to higher net interest income at Power as a result of certain 2003 FERC proceedings;

	•	$22.9 million higher impairments of cost-based investments;

	•	$25.3 million loss from investments in 2003 compared to $42.1 million income from investments in 2002; and

	•	$52.7 million lower equity earnings.

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

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

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

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

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


	•	$771.8 million impairment of assets;

	•	$97.7 million loss on sale of assets; and

	•	$301.7 million gain on sale of assets.

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

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

Results of operations — segments

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

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

Power


	*Overview of 2004*

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

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

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

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

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


	•	prices of power and natural gas, including changes in the margin between power and natural gas prices;

	•	changes in market liquidity, including changes in the ability to effectively hedge the portfolio;

	•	changes in power and natural gas price volatility;

	•	changes in interest rates;

	•	changes in the regulatory environment;

	•	changes in power and natural gas supply and demand; and

	•	the inability of counterparties to perform under contractual obligations due to their own credit constraints.


	*Outlook for 2005*

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

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

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


	•	market movements of commodity-based derivatives held for trading purposes or which did not qualify for hedge accounting; and


	•	ineffectiveness of cash flow hedges primarily caused by locational differences between the hedging derivative and the hedged item, changes in the creditworthiness of counterparties and the hedging derivative contract having a fair value upon designation.

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


	*Year-over-year operating results*


		Years Ended December 31,

		2004			2003		2002

		(Millions)
Realized revenues		$	8,954.7		$	12,930.5	$	(278.7	)*
Forward unrealized mark-to-market gains			304.0			262.1		193.5

	Segment revenues		9,258.7			13,192.6		(85.2	)
Cost of sales			9,073.3			12,954.6		28.9

	Gross margin		185.4			238.0		(114.1	)
Operating expenses			23.7			35.3		40.0
Selling, general and administrative expenses			83.2			124.0		209.0
Other income (expense) — net			(1.8	)		56.4		(263.1	)

	Segment profit (loss)	$	76.7		$	135.1	$	(626.2	)


*	In 2002, Power reported its trading operations’ physical sales transactions net of the related purchase costs. See Note 1 of Notes to Consolidated Financial Statements.


	2004 vs. 2003

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

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

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

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

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

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

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

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


	•	a $20 million charge for a settlement with the CFTC;

	•	accruals of $19.5 million for power marketing activities in California in prior periods (see Note 15 of Notes to Consolidated Financial Statements);

	•	a $45 million impairment of goodwill;

	•	a $44.1 million impairment on a power generating facility (see Note 4 of Notes to Consolidated Financial Statements); and

	•	a $14.1 million impairment associated with the Aux Sable partnership investment (see Note 4 of Notes to Consolidated Financial Statements).

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


	2003 vs. 2002

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

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


Before		After

Revenues:		Revenues:
	Realized revenues:	Realized revenues:
	• Revenue from sales of commodities or completion of energy-related services	• Revenue from sales of commodities or completion of energy-related services
	• Gains and losses from net financial settlement of derivative contracts	• Gains and losses from net financial settlement of derivative contracts
	• Costs from purchases of commodities or fees from energy-related services that were not associated with property, plant and equipment we owned
	Forward unrealized mark-to-market gains:	Forward unrealized mark-to-market gains:
	• Gains and losses from changes in fair value of all energy trading contracts with a future settlement or delivery date	• Gains and losses from changes in fair value of only derivative contracts with a future settlement or delivery date
Costs:		Costs:
	• Costs from purchases of commodities or fees from energy-related services for use in property, plant and equipment that we owned	• Costs from purchases of all commodities or fees for energy-related services

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

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

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


Derivative Contracts		Non-Derivative Contracts

• Forward purchase and sale contracts		• Spot purchase and sale contracts
• Futures contracts		• Transportation contracts
• Option contracts		• Storage contracts
• Swap agreements		• Tolling agreements (power conversion contracts)
		• Full requirement or load serving contracts (power sales contracts in which we supply all of the customer’s requirements for power)

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

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

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

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

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

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

Gas Pipeline


	*Overview of 2004*

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

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


	Northwest Pipeline in western Washington

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

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

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

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

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

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


	Momentum Phase II

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


	Georgia Strait Project

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


	*Outlook for 2005*


	Gulfstream Natural Gas System, L.L.C.

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


	Central New Jersey Expansion Project

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


	Significant risk factors

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


	•	legal and regulatory events such as FERC rate authorization and/or rate case settlements (see Note 15 of Notes to Consolidated Financial Statements),


	•	market demand for expansion projects to increase revenue and segment profit,

	•	catastrophic events affecting our infrastructure, such as pipeline ruptures, and

	•	regulatory accounting changes regarding pipeline assessment costs.


	*Year-over-year operating results*

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


	Years Ended December 31,

	2004		2003		2002

	(Millions)
Segment revenues	$	1,362.3	$	1,368.3	$	1,301.2
Segment profit	$	585.8	$	555.5	$	535.8


	2004 vs. 2003

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

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

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

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


	*Summarized changes in Gas Pipeline’s segment profit*

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


	•	the absence of the 2003 $25.6 million charge discussed above,

	•	$13.4 million higher equity earnings primarily from our investment in the Gulfstream Pipeline,

	•	$12 million higher revenues, excluding reimbursable costs that do not impact segment profit, and

	•	$5 million lower general and administrative expense, excluding reimbursable costs that do not impact segment profit.

These increases to segment profit were partially offset by the following:


	•	a $9 million charge for the write-off of previously capitalized costs discussed above,

	•	$9 million higher costs and operating expenses, excluding reimbursable costs that do not impact segment profit; and

	•	the absence of the 2003 $7.2 million of income resulting from a reduction of accrued liabilities discussed above.


	2003 vs. 2002

The $67.1 million, or five percent, increase in revenues is due primarily to $61 million higher demand revenues on the Transco system resulting from new expansion projects (MarketLink, Momentum and Sundance) and higher rates approved under Transco’s rate proceedings that became effective in late 2002 and $27 million on the Northwest Pipeline system resulting from new projects (Gray’s Harbor, Centralia, and Chehalis). Revenue also increased due to $14 million higher commodity revenue on Transco. Partially offsetting these increases was the absence in 2003 of $28 million of revenue from reductions in the rate refund liabilities and other adjustments associated with a rate case settlement on Transco in 2002 and $13 million lower storage demand revenues in 2003 due to lower storage rates in connection with Transco’s rate proceedings that became effective in late 2002.

Cost and operating expenses increased $21 million, or three percent, due primarily to $25 million higher depreciation expense due to additional property, plant and equipment placed into service and $12 million higher state sales and use, ad valorem and franchise taxes. These increases were partially offset by $15 million lower fuel expense on Transco, resulting primarily from pricing differentials on the volumes of gas used in operation.

General and administrative costs decreased $32 million, or 20 percent, due primarily to the absence in 2003 of $23 million of early retirement pension costs recorded in 2002 and other employee-related benefits costs associated with reduced employee levels as well as the absence of a $5 million write-off in 2002 of capitalized software development costs resulting from cancellation of a project.

Other (income) expense — net in 2003 includes a $25.6 million charge at Northwest Pipeline to write-off capitalized software development costs for a service delivery system. Subsequent to the implementation of the same system at Transco in the second quarter of 2003 and a determination of the unique and additional programming requirements that would be needed to complete the system at Northwest Pipeline, management determined that the system would not be implemented at Northwest Pipeline. Other (income) expense — net in 2003 also includes $7.2 million of income at Transco due to a partial reduction of accrued liabilities for claims associated with certain producers as a result of settlements and court rulings. Other income (expense) — net in 2002 includes a $17 million charge associated with a FERC penalty (see Investigations related to natural gas storage inventory in Note 15 of Notes to Consolidated Financial Statements) and a $3.7 million loss on the sale of the Cove Point facility.


	*Summarized changes in Gas Pipeline’s segment profit*

The $19.7 million, or four percent, increase in segment profit, which includes equity earnings and income (loss) from investments, is due to the following favorable 2003 items:


	•	the $67.1 million increase in revenues,

	•	the $32 million decrease in general and administrative costs,

	•	the absence of a 2002 $17 million FERC charge discussed above; and

	•	the absence of the 2002 $12.3 million write off of Gas Pipeline’s investment in a cancelled pipeline project and a 2002 $10.4 million loss on the sale of Gas Pipeline’s 14.6 percent ownership interest in Alliance Pipeline. Both items were included in income (loss) from investment, which is included in Investing income (loss).

These increases to segment profit were partially offset by the following:


	•	$73 million lower equity earnings,

	•	the $25.6 million charge at Northwest Pipeline to write-off capitalized software costs discussed previously,

	•	the $21 million higher operating costs, and

	•	the absence of a 2002 $8.7 million gain on the sale of our general partnership interest in Northern Border Partners, L.P.

The $73 million decrease to equity earnings reflects $24 million lower equity earnings from our investment in the Gulfstream Pipeline, the absence of a $27.4 million benefit in 2002 related to the contractual construction completion fee received by an equity affiliate and the absence of $19 million of equity earnings following the October 2002 sale of Gas Pipeline’s 14.6 percent ownership in Alliance Pipeline. The lower earnings from our investment in the Gulfstream Pipeline were primarily due to the absence in 2003 of interest capitalized on internally generated funds as allowed by the FERC during construction. The Gulfstream pipeline was placed into service during second-quarter 2002.

Exploration & Production


	*Overview of 2004*

In 2004, our strategy focused on expanding our development drilling program in order to surpass results experienced in prior years. We achieved this goal consistently throughout 2004 with our major accomplishments including the following:


	•	We increased daily production volumes by 27 percent from the beginning of the year. The domestic average daily production for the quarter ending December 31, 2004 was approximately 566 million cubic feet of gas equivalent (MMcfe) compared to 447 MMcfe for the same period in 2003.

	•	We increased our development drilling program throughout 2004, surpassing annual drilling capital expenditures prior to 2004 and more than doubling the expenditures occurring in 2003. Capital expenditures for domestic drilling activity in 2004 were approximately $436 million compared to approximately $200 million in 2003.

	•	We improved the timing and efficiency of our drilling cycle, particularly in the Piceance basin, by reducing the number of days to drill from eighteen to sixteen, thereby increasing the number of wells drilled during a given time period.

The benefit of the higher production volumes was partially offset by increased operating costs and lower net average realized prices which were the result of increased derivative hedge losses in 2004. The increase in operating costs was the result of escalated overall production and maintenance activities among oil and gas producers, which caused service companies to increase their fees.


	*Outlook for 2005*

Our expectations for 2005 include:


	•	a continuing development drilling program in our key basins with an increase in activity in the Piceance, San Juan, and Arkoma basins with associated planned capital expenditures of $500 million to $575 million in 2005; and

	•	increasing our fourth-quarter 2004 average daily domestic production level of 566 MMcfe per day by at least ten percent by the end of 2005.

Approximately 286 MMcfe of our forecasted 2005 daily domestic production of 600 to 700 MMcfe per day is hedged at prices that average $4.00 per MMcfe at a basin level. In addition, we have approximately 50 MMcfe of our daily estimated January 2005 through March 2005 production hedged in NYMEX collar agreements that have an average floor price of $7.50 per MMcfe and an average ceiling price of $10.49 per MMcfe at a basin level.

Risks that we may not be able to accomplish our objectives include drilling rig availability as well as obtaining permits as planned for drilling.


	*Year-over-year operating results*

The following discussions of the year-over-year results primarily relate to our continuing operations. However, the results do include those operations that were sold during 2003 or 2002 that did not qualify for discontinued operations reporting. The operations classified as discontinued operations are the properties in the Hugoton and Raton basins.


	Years Ended December 31,

	2004		2003		2002

	(Millions)
Segment revenues	$	777.6	$	779.7	$	860.4
Segment profit	$	235.8	$	401.4	$	508.6


	2004 vs. 2003

The $2.1 million, or less than one percent, decrease in revenues is primarily due to the absence of $24 million in income realized during 2003 from derivative instruments that did not qualify for hedge accounting, partially offset by an increase in domestic production revenues of $22 million during 2004. The increase in domestic production revenues primarily results from $49 million higher revenues associated with a nine percent increase in production volumes partially offset by $27 million lower revenues associated with a four percent decrease in net realized average prices for production sold. Net realized average prices include the effect of hedge positions which were at prices below market levels. The increase in production volumes primarily reflects an increase in the number of producing wells resulting from our successful 2004 drilling program. We expect production volumes to continue to increase in 2005 as our development drilling program continues.

To manage the risk and volatility associated with the ownership of producing gas properties, we enter into derivative forward sales contracts that economically lock in a price relating to a portion of our future production. Approximately 77 percent of domestic production in 2004 was hedged at a weighted average price of $3.65 per MMcfe at a basin level. These hedges are executed with our Power segment which, in turn, executes offsetting derivative contracts with unrelated third parties. Generally, Power bears the counterparty performance risks associated with unrelated third parties. Hedging decisions are made considering our overall commodity risk exposure and are not executed independently by Exploration & Production.

Total costs and expenses increased $167 million, which includes the absence of $95 million in net gains on sales of assets occurring in 2003. The remaining increase in costs and expenses primarily reflects:


	•	$18 million higher depreciation, depletion and amortization expense primarily as a result of increased production volumes as well as increased capitalized drilling costs reflective of greater levels of drilling and increased prices for tubular goods occurring in response to supply conditions in the worldwide steel market;

	•	$20 million higher lease operating expense associated with the higher number of producing wells and an increase in well maintenance activities, higher labor and fuel costs, and an increase in overhead payments to another operator;

	•	$17 million higher operating taxes due primarily to increased production volumes sold;

	•	a $16 million gain attributable to the sales of securities, associated with a coal seam royalty trust, that were purchased for resale; and

	•	a $15.4 million loss provision regarding an ownership dispute on prior period production.

The $165.6 million decrease in segment profit is due primarily to the absence of $95 million in net gains on sales of assets occurring in 2003, the increase in operating expenses, and the loss provision of $15.4 million relating to an ownership dispute on prior period production partially offset by the $16 million gain attributable to the sales of securities associated with our coal seam royalty trust that were purchased for resale. Segment profit also includes $25 million and $18 million related to international activities for 2004 and 2003, respectively. This increase is primarily driven by the improved operating results of Apco Argentina.


	2003 vs. 2002

The $80.7 million, or nine percent decrease in revenues is due primarily to $66 million lower production revenues due to lower production volumes as the result of property sales and reduced drilling activities and $21 million lower other revenues primarily due to the absence in 2003 of deferred income relating to transactions in prior years that transferred certain economic benefits to a third party.

The decrease in domestic production revenues reflects $68 million associated with an eleven percent decrease in net domestic production volumes, partially offset by $2 million higher revenues from increased net realized average prices for production. Net realized average prices include the effect of hedge positions. The decrease in production volumes primarily results from the sales of properties in 2002 and 2003 and the impact of reduced drilling activity. Drilling activity was lower in the January through August period of 2003 due to our capital constraints. During the third quarter, drilling activities on our retained properties began to increase and by the fourth quarter of 2003 returned to levels more consistent with 2002 levels. Approximately 86 percent of domestic production in 2003 was hedged using the same methodology discussed above.

Total costs and expenses increased $32 million primarily due to $46 million lower net gains on sales of assets in 2003 as compared to 2002. The remaining variance in costs and expenses primarily reflects:


	•	$17 million lower exploration expenses reflecting our focus of the company on developing proved properties while reducing exploratory activities;

	•	$10 million lower depreciation, depletion and amortization expense primarily as a result of lower production volumes;

	•	$7 million lower selling, general and administrative expense; and

	•	$19 million higher operating taxes due primarily to higher market prices.

The $107.2 million decrease in segment profit is due primarily to $46 million lower net gains on sales of assets in 2003 as compared to 2002, as discussed above. Additionally, lower production revenues due primarily to lower production volumes also contributed to the decrease. Segment profit also includes $18.2 million and $11.8 million related to international activities for 2003 and 2002, respectively. This increase is primarily driven by the improved operating results of Apco Argentina.

Midstream Gas & Liquids


	*Overview of 2004*

In 2004, we continued to expand our Midstream operations where we have large scale assets that are positioned in growth basins and to divest less strategic assets. Consistent with this plan, we placed into service additional infrastructure in the deepwater offshore area of the Gulf of Mexico and expanded the Opal gas processing facility in Wyoming. In the deepwater Gulf of Mexico, the Devils Tower production handling facility, the Canyon Chief gas pipeline, and the Mountaineer oil pipeline began flowing product in May 2004, while the Gunnison oil pipeline volumes increased throughout the year. Our ongoing focus is to develop and operate large-scale Midstream infrastructure where our assets can be fully utilized and provide the highest level of reliability to our customers.

The following factors impacted our business during 2004.


	•	Substantial Completion of Our Asset Sales Goals — In 2004, we completed our asset sales program. The July sale of the western Canadian straddle plants represented our most significant divestiture of 2004 yielding approximately $544 million in U.S. funds. The estimated pre-tax gain on sale of approximately $190 million was recognized in discontinued operations in the third quarter.

	•	Favorable Commodity Price Margins — Our natural gas liquids (NGL) margins benefited from a significant increase in crude oil prices and an increased demand for petrochemical feedstocks such as ethane and propane. As indicated in the graph below, our quarterly margins exceeded the historical five-year annual average throughout the second half of 2004. Our gas processing facilities produced strong financial results as a result of near record high NGL margins and operated at full capacity throughout most of the year. Our olefins businesses also benefited from favorable commodity prices associated with additional demand for ethylene and propylene.


	•	Impact of Hurricane Ivan — In September 2004, portions of our Gulf Coast operations were interrupted by Hurricane Ivan. The Mobile Bay gas processing plant, Canyon Station and Devils Tower platforms were located in the path of the hurricane and incurred varying levels of damage. Hurricane Ivan caused temporary shut-downs of both our facilities and producers’ facilities, which reduced product flows resulting in lower segment profit of approximately $11 million in 2004. The majority of the repairs related to Hurricane Ivan are expected to be covered by our insurance. Repairs to the Devils Tower facility were completed in October 2004 while our other impacted assets were returned to service by the end of September 2004. However, product flows to our deepwater

facilities were reduced significantly during the fourth-quarter as incidental damage to our customers’ facilities was being repaired.

• Gulf Liquids Reclassification to Continuing Operations — During fourth-quarter 2004, we reclassified the operations of Gulf Liquids to continuing operations within our Midstream segment in accordance with EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations,” (EITF 03-13). Under the provisions of EITF 03-13, Gulf Liquids no longer qualifies for reporting as discontinued operations based on management’s expectation that we will continue to have significant commercial activity with the disposed entity. All periods presented reflect this restatement.

• Gulf Liquids Insurance Arbitration Award — During fourth-quarter 2004, an arbitration panel awarded Gulf Liquids $93.6 million, plus interest of $9.6 million. Prior to this judgment, the insurer had disputed coverage of certain financial assurances provided to Gulf Liquids on multiple construction contracts.

• Compliance with FERC Order 2004 — Effective June 1, 2004, and due in part to our response to FERC Order 2004, management and decision-making control of certain regulated gas gathering assets was transferred from our Midstream segment to our Gas Pipeline segment. We also requested a waiver from the FERC regarding compliance with FERC Order 2004 for the operation of Discovery Gas Transmission and Black Marlin assets. In July 2004, the FERC granted a partial waiver allowing our Midstream segment to continue to manage these assets without subjecting Midstream to energy affiliate status under FERC Order 2004. In order to comply with the remaining provisions of the FERC order, we determined it was necessary to transfer management of our equity investment in the Aux Sable processing plant to our Power segment. This transfer was effective September 21, 2004. All periods presented reflect these classifications.


	*Outlook for 2005*

The following factors could impact our business in 2005 and beyond.


	•	As evidenced in recent years, natural gas and crude oil markets are highly volatile. Although NGL margins earned at our gas processing plants in 2004 were very favorable, we expect unit margins in 2005 to trend downward towards historical averages. NGL production volumes at our facilities are expected to be at or above levels of previous years due to continued strong drilling activities in our core basins.

	•	We are planning to expand our investment in the Wamsutter gathering system in 2005 and 2006.

	•	Our olefins unit margins were also favorable in 2004. While we believe this trend should continue in the near term, olefins margins are highly volatile and levels in 2004 are not necessarily indicative of levels expected for 2005. However, a fire at a Canadian oil sands facility that supplies us with off-gas feedstock reduced our throughput in January 2005. We expect this throughput reduction to continue through late 2005, partially offsetting the expected favorable margins.

	•	Continued growth in the deepwater areas of the Gulf of Mexico is expected to contribute to, and become a larger component of, our future segment revenues and segment profit. We expect these additional fee-based revenues to lower our proportionate exposure to commodity price risks.

	•	We continue efforts to sell our Gulf Liquids refinery off-gas and propylene splitting business in Louisiana and anticipate closing by the end of the second quarter of 2005.


	*Period-over-period results*


			Years Ended December 31,

			2004		2003			2002

			(Millions)
Segment revenues			$	2,882.6	$	2,784.8		$	1,183.7
Segment profit (loss)
	Domestic Gathering & Processing			342.7		272.9			203.5
	Venezuela			83.4		74.9			75.4
	Other			123.6		(150.5	)		(106.7	)

		Total	$	549.7	$	197.3		$	172.2


	2004 vs. 2003

The $97.8 million increase in Midstream’s revenues is primarily the result of favorable commodity prices on our gas processing and olefins businesses, largely offset by lower trading revenues resulting from the fourth-quarter 2003 sale of our wholesale propane business. Revenues associated with production of NGLs increased $417 million, of which $214 million is due to higher volumes and $203 million is due to higher NGL prices. Olefins revenues increased $223 million as a result of both higher market prices and higher volumes. In addition, our deepwater service revenues increased $9 million due to the addition of new infrastructure. Other factors affecting total revenues include approximately $1 billion in lower trading revenues resulting from the fourth-quarter 2003 sale of our wholesale propane business, partially offset by a $263 million increase as the result of marketing NGLs on behalf of our customers. Before 2004, our purchases of customers’ NGLs were netted within revenues. In 2004, these purchases of customers’ NGLs are included in costs and operating expenses which substantially offset the change in revenues. Of this $263 million increase, approximately $146 million results from the difference in financial reporting presentation; the remaining increase is due to higher NGL volumes and prices. Also partially offsetting the lower trading revenues is $141 million in higher crude sales associated with the 2004 startup of one of our deepwater pipelines, which is offset in costs and operating expenses below.

Costs and operating expenses decreased $56 million primarily as a result of approximately $1 billion in lower trading costs due to the sale of our wholesale propane business in 2003. This decline was partially offset by $312 million in higher costs related to the production of NGLs and $157 million in higher costs related to the production of olefins products. These costs increased as a result of both the higher production volumes noted above and the higher prices for natural gas and olefins feedstock. Maintenance and depreciation expenses increased $33 million in large part due to newly constructed deepwater assets. Similar to the impact to revenues, total costs and operating expenses increased $263 million due to the marketing of NGLs on behalf of customers and $141 million in higher crude purchases related to the same deepwater pipeline mentioned above.

The $352.4 million increase in Midstream segment profit includes the $93.6 million gain from the Gulf Liquids’ insurance arbitration award in 2004 and the absence of a $108.7 million impairment charge in 2003 related to these same assets both of which are included in Other (income) expense - net, within operating income. The remaining increase in segment profit is primarily due to higher NGL and olefins production volume and unit margins, higher service revenues, and reduced general and administrative expenses. These increases are partially offset by higher operating expenses and asset impairment charges. A more detailed analysis of segment profit of Midstream’s various operations is presented below.

Domestic Gathering & Processing: The $69.8 million increase in domestic gathering and processing segment profit includes a $59.6 million increase in the West region and an $10.2 million increase in the Gulf Coast region.

The $59.6 million increase in our West region’s segment profit reflects higher NGL volume and unit margins offset by lower fee revenues and higher operating expenses. The significant components of this increase are explained below.


	•	Our West region’s net NGL margins for 2004 increased $69 million compared to the same period in 2003. Net NGL margins are defined as NGL revenues less BTU replacement cost, plant fuel, transportation and fractionation expense. Average per unit NGL margins increased 49 percent and comprised $51 million of the increase in NGL margins. As a result of the higher spread between the prices of NGLs and natural gas, our West plants operated at near capacity and produced 21 percent higher volumes comprising the remaining $18 million increase in NGL net margins.

The $10.2 million increase in our Gulf Coast region’s segment profit is due to higher NGL margins partially offset by lower fee revenues and higher depreciation expense. The significant components of the net increase include the following.


	•	Net NGL margins at our Gulf Coast gas processing plants increased $35 million due to a 101 percent increase in NGL production volumes which represented $28 million of the increase in margins. The significantly higher NGL volumes were driven by the favorable spread between NGL and natural gas prices coupled with the recently completed production handling infrastructure flowing additional deepwater gas production to our plants. Per unit margins in the Gulf Coast region increased 13 percent and comprised the remaining $7 million increase in net NGL margins.

	•	Segment profit from our deepwater assets declined $21 million primarily due to $29 million in higher costs associated with assets placed into service in the first two quarters of 2004 partially offset by $9 million in higher services revenues. The increase in revenues includes $22 million in incremental revenues from newly constructed assets partially offset by a $13 million decline in handling and gathering revenues due to lower production volumes on other deepwater assets substantially resulting from the effects of Hurricane Ivan. While revenues from the Devils Tower deepwater facility are recognized as volumes are delivered over the life of the reserves, cash payments from our customer are based on a contractual fixed fee received over a defined term. As a result, $36 million of cash received, which is included in cash flow from operations, was deferred at December 31, 2004 and will be recognized as revenue in future periods.

Venezuela: The $8.5 million increase in segment profit for our Venezuelan assets is primarily due to the absence of a fire at the El Furrial facility that reduced revenues by $10 million in the first quarter of 2003.

Other: The $274.1 million increase in segment profit in our other businesses includes the $93.6 million Gulf Liquids insurance arbitration award and the absence of $108.7 million in Gulf Liquids impairment charges in 2003. The remaining increase is comprised of the following.


	•	Combined margins from our olefins businesses improved $66 million reflecting the overall improvement in olefins pricing and higher production volumes. Market prices for ethylene and propylene products increased due to higher demand and lower inventories. Production volumes increased as a result of increased spot sales and the new higher fixed margin contract at our Giesmar facility while our Canadian and Gulf Liquids volumes benefited from improved plant operations.

	•	Selling, general and administrative expenses declined $23 million largely due to asset sales and lower legal expenses.

	•	The favorable variances above are partially offset by a 2004 $16.9 million impairment charge related to our equity investment in the Discovery partnership, reflecting management’s assessment that there has been an other-than-temporary decline in the value of this investment.


	2003 vs. 2002

Revenues increased $1.6 billion primarily as a result of adopting EITF 02-3, which changed how we report natural gas liquids trading activities. The costs of such activities are no longer reported as reductions in revenues. EITF 02-3 does not require restatement of prior year amounts. In addition to this effect, our

revenues increased $210 million primarily due to higher NGL revenues at our gas processing plants as a result of moderate market price increases, partially offset by lower NGL production volumes. Additional fee revenues associated with newly constructed deepwater assets and higher olefins sales also contributed to the revenue increase.

Costs and operating expenses also increased $1.9 billion primarily due to the adoption of EITF 02-3 as discussed in the previous paragraph. In addition to this effect, costs and expenses increased $360 million, of which $113 million is attributable to rising market prices for natural gas used to replace the heating value of NGLs extracted at our gas processing facilities. Feedstock purchases for the olefins facilities increased $214 million due to higher NGL and gas prices as well as higher purchase volumes.

Segment profit increased $25.1 million and includes impairment charges of $108.7 million in 2003 related to the Gulf Liquids facilities and $78.2 million in 2002 relating to the Redwater/ Fort McMurray olefins assets. The remaining $55.6 million increase is largely attributable to higher deepwater and other Gulf Coast fee revenues partially offset by unfavorable results in our Canadian and Gulf olefins operations. Segment profit benefited from increased processing margins in both 2003 and 2002 due to rising NGL prices coupled with depressed natural gas prices in the Wyoming area. In contrast, Canadian and Gulf olefins production margins suffered as market prices for ethane and propane feedstocks increased more than those for the olefins produced at these facilities, which lowered operating results. In addition, gains on asset and investment sales, reduced selling, general and administrative expenses, and gathering system net gains are offset by lower partnership earnings and higher depreciation expense. A more detailed analysis of segment profit of our various operations is presented below:

Domestic Gathering & Processing: The $69.4 million increase in domestic gathering and processing segment profit includes a $76.1 million increase in the Gulf Coast region, partially offset by a $6.7 million decline in the West region.

The Gulf Coast region’s $76 million improvement is largely attributable to $42 million of incremental segment profit associated with new infrastructure in the deepwater area of the Gulf of Mexico. The Canyon Station production platform, Seahawk gas gathering pipeline, and Banjo oil transportation system were placed into service during the latter half of 2002 and each contributed to Midstream’s segment profit. The remaining Gulf Coast gathering and processing assets provided approximately $34 million in additional net revenues, primarily from $12 million in higher processing margins and $23 million in higher fee-based revenues. A portion of this increase relates to the temporary processing agreements which allow producers’ gas to be processed to achieve pipeline quality standards.

The West region’s $6.7 million segment profit decline reflects the absence of $7 million in operating profit associated with the Kansas Hugoton gathering system sold in August 2002. Although 2003 segment profit is comparable to 2002, the West region’s segment results were impacted by several offsetting factors discussed below.


	•	Gas processing margins declined $10 million compared to margins experienced in 2002. Throughout 2002 and the first quarter of 2003, rising NGL prices and depressed Wyoming natural gas prices yielded very favorable processing margins. Wyoming natural gas prices rebounded at the end of the first quarter 2003 as the completion of the Kern River Pipeline system added transportation capacity relieving downward price pressure. Margins recovered somewhat in the fourth quarter as Wyoming gas prices lagged behind the increases in other energy commodities.

	•	Gathering and processing fee revenues declined $11 million primarily due to fewer customers electing the fee-based billing option of processing contracts.

	•	Non-reimbursed fuel expenses declined $8 million, largely attributed to favorable adjustments in the annual fuel reimbursement rates.

	•	We realized $17 million in non-recurring net product gains related to our gas gathering system. These gains represent less than one-third of one percent of total gas gathered and are within industry

standards. Historically our gathering system realizes net gains and losses, and therefore, we do not consider these gains to be recurring in nature.

• Depreciation expense was $10 million higher in large part due to additional investments in the West region.

Venezuela: Segment profit for our Venezuelan assets remained virtually unchanged. Higher compression rates in 2003 and the 2002 currency exchange loss resulted in $11 million higher profits at the PIGAP gas compression facility. These higher profits were partially offset by an $10 million decrease in the El Furrial revenues attributed to plant downtime caused by a fire that occurred in the first quarter of 2003. Also offsetting the increase in PIGAP operating profit is a $4 million decline resulting from the termination of the Jose Terminal operations contract in December 2002. Our Venezuelan assets were constructed and are currently operated for the exclusive benefit of Petroleos de Venezuela S.A. (PDVSA), the state owned Petroleum Corporation of Venezuela. The Venezuelan economic and political environment can be volatile, but has not significantly impacted the operations and cash flows of our facilities.

Effective February 7, 2004, the Venezuelan government revalued the fixed exchange rate for their local currency from 1,600 Bolivars to the dollar to 1,920 Bolivars to the dollar. This effect of this currency devaluation was recorded in the first quarter of 2004 and did not have a significant impact on our first quarter segment profit.

Other: The $43.8 million decline in segment profit for Midstream’s other operations includes impairment charges of $108.7 million in 2003 related to the Gulf Liquids facilities and the absence of $78.2 million of profit in 2002 relating to the Redwater/ Fort McMurray olefins assets. The remaining decrease is attributed to lower domestic olefins margins and unfavorable partnership earnings, partially offset by the gain on sale of our wholesale propane operations as discussed below.


	•	Excluding impairment charges, segment profit for our olefins businesses declined $26 million primarily as a result of reduced olefins margins as the price of ethane, propane, and natural gas feedstocks increased more than the price of olefins products. Higher maintenance expenses also contributed to the decline in segment profit. Olefins production margins continue to be impacted by weak consumer demand for products produced by petrochemical facilities.

	•	Segment profit from partially owned domestic assets accounted for using the equity method remained largely unchanged and includes $21 million lower earnings from partially-owned investments primarily resulting from $13 million in prior period accounting adjustments recorded on the Discovery partnership and the 2003 sale of other investments that generated $5 million in higher 2002 earnings. These unfavorable results were partially offset by net gains totaling approximately $20 million from the sale of our interests in the West Texas, Rio Grande, Wilprise, and Tri-States liquids pipeline partnerships.

	•	Segment profit for our trading, fractionation, and storage group increased $14 million primarily due to a $16 million gain on the fourth-quarter 2003 sale of our wholesale propane business consisting of certain supply contracts and seven propane distribution terminals. Our NGL trading operations activities were substantially curtailed in 2003, resulting in $11 million lower selling, general, and administrative costs partially offset by $8 million in lower net trading revenues. In addition, NGL service fees declined $5 million due to the sale of several NGL terminals in 2002.

Other


	*Overview of 2004*

During February 2004, we were a party to a recapitalization plan completed by Longhorn. As a result of this plan, we sold a portion of our equity investment in Longhorn for $11.4 million, received $58 million in repayment of a portion of our advances to Longhorn and converted the remaining advances, including accrued interest, into preferred equity interests in Longhorn. These preferred equity interests are subordinate to the preferred interests held by the new investors. No gain or loss was recognized on this transaction.


	*Outlook for 2005*

In 2005, we expect to see improved results from our investment in Longhorn. The first product shipments on the Longhorn pipeline occurred in December 2004 and volumes should increase throughout 2005. New shippers have been approved and more approvals are currently in process. In addition, during the first quarter of 2005, we finalized a sales agreement on our Longhorn operating agreement. The sale is expected to close during the first quarter or early in the second quarter of 2005. We expect to receive proceeds on the sale over the remaining term of the operating agreement, which expires on June 30, 2012. We do not expect to recognize a gain or loss on the sale.


	*Year-over-year operating results*


	Years Ended December 31,

	2004			2003			2002

	(Millions)
Segment revenues	$	32.8		$	72.0		$	124.1
Segment profit (loss)	$	(41.6	)	$	(50.5	)	$	14.1


	2004 vs. 2003

Other segment revenues for 2003 includes approximately $22 million of revenues related to certain butane blending assets, which were sold during third-quarter 2003.

Other segment loss for 2004 includes $11.8 million of accrued environmental remediation expense associated with the Augusta refinery, and a $10.8 million impairment, $9.8 million of equity losses, and $6.5 million of net unreimbursed advisory fees, all related to our investment in Longhorn. The environmental accrual results from new information obtained in the fourth quarter of 2004. The impairment charge reflects management’s belief that there was an other than temporary decline in the fair value of this investment following a determination that additional funding would be required to commission the pipeline into service. The project incurred cost overruns in preparation for commissioning, including higher priced line fill costs. The net unreimbursed advisory fees relate to the recapitalization of Longhorn as discussed above. If the project achieves certain future performance measures, the unreimbursed fees may be recovered.

Other segment loss for 2003 includes a $43.1 million impairment related to our investment in equity and debt securities of Longhorn. The impairment resulted from our assessment that there had been an other than temporary decline in the fair value of this investment.


	2003 vs. 2002

Other segment loss for 2003 includes the $43.1 million impairment of Longhorn noted above. Longhorn equity earnings increased $15.7 million during 2003 from a loss of $13.8 million in 2002. The 2002 segment profit includes a $58.5 million gain on the sale of our 27 percent ownership interest in the Lithuanian operations partially offset by a $12.6 million equity loss for those operations.

Energy trading activities

As of December 31, 2002, we held all of these energy and energy-related contracts for trading purposes and carried them on the Consolidated Balance Sheet at fair value. With the adoption of EITF 02-3 on January 1, 2003, we reversed approximately $1.2 billion of non-derivative fair value through a cumulative adjustment from a change in accounting principle. These contracts are now accounted for under the accrual method. Effective January 1, 2003, only energy contracts meeting the definition of a derivative are reflected at fair value on the Consolidated Balance Sheet.


	*Fair value of trading and non-trading derivatives*

The chart below reflects the fair value of derivatives held for trading purposes as of December 31, 2004. We have presented the fair value of assets and liabilities by the period in which we expect them to be realized.

Net Assets (Liabilities)

(Millions)


To be		To be		To be			To be
Realized in		Realized in		Realized in			Realized in
1-12 Months		13-36 Months		36-60 Months			61-120 Months			Net Fair
(Year 1)		(Years 2-3)		(Years 4-5)			(Years 6-10)			Value

$	15	$	16	$	(3	)	$	(2	)	$	26

As the table above illustrates, we are not materially engaged in trading activities. However, we hold a substantial portfolio of non-trading derivative contracts. Non-trading derivative contracts are those that hedge or could possibly hedge on an economic basis forecasted transactions associated with Power’s long-term structured contract position and owned generation, Exploration & Production’s forecasted sales of natural gas production, as well as the activities of our other segments. As a result of our decision to retain the Power business, in the fourth quarter of 2004 we designated a portion of the existing derivatives as SFAS 133 cash flow hedges. Many of these non-trading derivatives had an existing fair value prior to their designation as cash flow hedges. Certain other of Power’s derivatives have not been designated as or do not qualify as SFAS 133 hedges. We also hold certain derivative contracts, which also qualify as SFAS 133 cash flow hedges, that primarily hedge Exploration & Production’s forecasted natural gas sales. The chart below reflects the fair value of derivatives held for non-trading purposes as of December 31, 2004. Of the total fair value of non-trading derivatives, SFAS 133 cash flow hedges had a net liability value of $328.8 million as of December 31, 2004, which includes the fair value of the derivatives upon their designation as SFAS 133 cash flow hedges.

Net Assets (Liabilities)

(Millions)

To be

Realized in

1-12 Months

13-36 Months

36-60 Months

61-120 Months

121+ Months

Net Fair

(Year 1)

(Years 2-3)

(Years 4-5)

(Years 6-10)

(Years 11+)

Value

120

108

365


	*Methods of estimating fair value*

Most of the derivatives we hold settle in active periods and markets in which quoted market prices are available. Quoted market prices in active markets are readily available for valuing, future contracts, swap agreements and physical commodity purchases and sales in the commodity markets in which we transact. While an active market may not exist for the entire period, quoted prices can generally be obtained for natural gas through 2012 and power through 2010.

These prices reflect the economic and regulatory conditions that currently exist in the marketplace and are subject to change in the near term due to changes in market conditions. The availability of quoted market prices in active markets varies between periods and commodities based upon changes in market conditions.

The ability to obtain quoted market prices also varies greatly from region to region. The time periods noted above are an estimation of aggregate liquidity. An immaterial portion of our total net derivative value of $391 million relates to periods in which active quotes cannot be obtained. We use prices of current transactions to further validate price estimates. However, the decline in overall market liquidity since 2002 has limited our ability to validate prices.

We estimate energy commodity prices in illiquid periods by incorporating information about commodity prices in actively quoted markets, quoted prices in less active markets, and other market fundamental analysis.

Due to the adoption of EITF 02-3, modeling and other valuation techniques are not used significantly in determining the fair value of our derivatives. Such techniques were primarily used in previous years for valuing non-derivative contracts such as transportation, storage, full requirements, load serving, transmission and power tolling contracts, which are no longer reported at fair value (see Note 1 of Notes to Consolidated Financial Statements).


	*Counterparty credit considerations*

We include an assessment of the risk of counterparty non-performance in our estimate of fair value for all contracts. Such assessment considers 1) the credit rating of each counterparty as represented by public rating agencies such as Standard & Poor’s and Moody’s Investors Service, 2) the inherent default probabilities within these ratings, 3) the regulatory environment that the contract is subject to and 4) the terms of each individual contract.

Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. We continually assess this risk. We have credit protection within various agreements to call on additional collateral support if necessary. At December 31, 2004, we held collateral support of $336 million.

We also enter into netting agreements to mitigate counterparty performance and credit risk. During 2004, we did not incur any significant losses due to recent counterparty bankruptcy filings.

The gross credit exposure from our derivative contracts as of December 31, 2004 is summarized below.


	Investment
Counterparty Type	Grade(a)		Total

	(Millions)
Gas and electric utilities	$	556.4	$	609.4
Energy marketers and traders		1,185.7		3,268.3
Financial institutions		2,023.9		2,023.9
Integrated gas and oil		90.0		90.0
Other		5.6		21.1

	$	3,861.6		6,012.7

Credit reserves				(26.4	)

Gross credit exposure from derivatives(b)			$	5,986.3

We assess our credit exposure on a net basis. The net credit exposure from our derivatives as of December 31, 2004 is summarized below.


	Investment
Counterparty Type	Grade(a)		Total

	(Millions)
Gas and electric utilities	$	93.4	$	119.8
Energy marketers and traders		454.9		613.3
Financial institutions		217.4		217.4
Other		1.1		1.6

	$	766.8		952.1

Credit reserves				(26.4	)

Net credit exposure from derivatives(b)			$	925.7


(a)		We determine investment grade primarily using publicly available credit ratings. We included counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade. We also classify counterparties that have provided sufficient collateral, such as cash, standby letters of credit, adequate parent company guarantees, and property interests, as investment grade.

(b)		One counterparty within the California power market represents more than ten percent of the derivative assets and is included in investment grade. Standard & Poor’s and Moody’s Investors Service do not currently rate this counterparty. We included this counterparty in the investment grade column based upon contractual credit requirements.


	*Trading Policy*

We have policies and procedures that govern our trading and risk management activities and transactions. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations. Power’s value-at-risk is limited in aggregate and calculated at a 95 percent confidence level.

Financial condition and liquidity


	*Liquidity*


	Overview of 2004

Entering 2003, we faced significant liquidity challenges with sizeable maturing debt obligations and limited financial flexibility due in part to covenants arising from 2002 short-term financing. In February 2003, we outlined our planned business strategy to address these issues.

During 2003, we made substantial progress in strengthening our finances by generating cash proceeds of approximately $3.0 billion from asset sales, retiring $3.2 billion in debt, redeeming $275 million in preferred stock and issuing $2 billion in debt at more favorable market rates.

In 2004, we continued to execute certain components of the plan. Our key results for 2004 include the following.


	•	The replacement of our cash-collateralized letter of credit and revolver facility with facilities that do not encumber cash.

	•	Completion of planned asset sales, which resulted in proceeds of approximately $877.8 million (see further discussion in Investing activities).

	•	Significant debt reduction of approximately $4 billion in 2004 through scheduled maturities and early redemptions, including an exchange offer for our FELINE PACS units (see further discussion in Financing activities).

	•	Reduction of the risk and liquidity requirements of our Power business. As discussed previously, our Board of Directors approved the decision to retain Power and end our efforts to exit that business. We have and will continue to manage this business to minimize financial risk, generate cash and manage existing contractual commitments. During 2004, we reduced risk through the sale, termination or expiration of certain contracts and through entering into new contracts that economically hedge existing positions.

	•	Additional net reduction of $33 million in our selling, general and administrative costs and general corporate expenses. In an effort to further reduce costs in the future, we entered into an agreement with IBM to provide support services for certain areas of our business as discussed previously.


	Sources of liquidity

Our liquidity is derived from both internal and external sources. Certain of those sources are available to us (at the parent level) and others are available to certain of our subsidiaries.

At December 31, 2004, we have the following sources of liquidity from cash and cash equivalents:


	•	cash-equivalent investments at the corporate level of $735 million as compared to $2.2 billion at December 31, 2003, and

	•	cash and cash-equivalent investments of various international and domestic entities of $195 million, as compared to $91 million at December 31, 2003

At December 31, 2004, we have capacity of $28 million available under our two unsecured revolving credit facilities totaling $500 million. In April 2004, we entered into two unsecured bank revolving credit facilities totaling $500 million. These facilities provide for both borrowings and letters of credit, but are used primarily for issuing letters of credit. Use of these new facilities released approximately $496 million of restricted cash, restricted investments and margin deposits in the second quarter. In January 2005, these facilities were terminated and replaced with two new facilities that contain similar terms but fewer restrictions (see Note 11 of Notes to Consolidated Financial Statements).

At December 31, 2004, we also have capacity of $853 million available under our $1.275 billion secured revolving facility. On May 3, 2004, we entered into a new three-year, $1 billion secured revolving credit facility

which is available for borrowings and letters of credit. In August 2004, we expanded the credit facility by an additional $275 million. Northwest Pipeline and Transco each have access to $400 million under the facility, which is secured by certain Midstream assets and guaranteed by Williams Gas Pipeline Company, LLC, the parent company of Transco and Northwest Pipeline (WGP) (see Note 11 of Notes to the Consolidated Financial Statements).

At December 31, 2003, we had capacity of $447 million available under the $800 million revolving and letter of credit facility which was terminated on May 3, 2004.

We have an effective shelf registration statement with the Securities and Exchange Commission that authorizes us to issue an additional $2.2 billion of a variety of debt and equity securities. In addition, our wholly owned subsidiaries, Northwest Pipeline and Transco, also have outstanding registration statements filed with approximately $350 million of shelf availability remaining under these registration statements at December 31, 2004. Our ability to utilize these registration statements for debt securities was restricted by certain covenants of our debt agreements at December 31, 2004. On January 20, 2005, this restriction was removed from the parent and from Transco with the replacement of our two unsecured revolving credit facilities (see Note 11 of Notes to the Consolidated Financial Statements). Interest rates, market conditions, and industry conditions will affect amounts raised, if any, in the capital markets.

During 2004, we satisfied liquidity needs with:


	•	$1.1 billion in cash generated from sales of investments, property, and other assets, including the sale of the Alaska refinery and related assets and the sale of the Canadian straddle plants;

	•	approximately $1.5 billion in cash generated from operating activities of continuing operations, including the release of approximately $212 million of restricted cash and margin deposits previously used to collateralize certain credit facilities; and

	•	the release of approximately $284 million of restricted investments previously used to collateralize certain credit facilities.


	Credit ratings

As part of executing the business plan announced in February 2003, we established a goal of returning to investment grade ratios. Our decision to remain in the Power business could delay that goal. Our Standard and Poor’s, Moody’s Investors Service (Moody’s), and Fitch Ratings (Fitch) debt ratings at December 31, 2004 are as follows.

Current Senior Unsecured Debt Ratings

Northwest

Williams

Pipeline

Transco

Standard & Poor’s

B+

Moody’s Investors Service

Ba2

Fitch Ratings

BB+

On July 30, 2004, Standard & Poor’s raised our debt ratings outlook from negative to stable citing our debt reduction efforts. With respect to Standard & Poor’s, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “B” rating indicates that Standard and Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but that adverse business, financial or economic conditions will likely impair the obligor’s capacity or willingness to meet its financial commitment to the obligation. Standard and Poor’s may modify its ratings with a “+” or a “— ” sign to show the obligor’s relative standing within a major rating category.

On November 8, 2004, Moody’s Investors Service raised our senior implied rating to Ba3 from B2 and our senior unsecured rating to B1 from B3, with a stable outlook. With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative

elements. A “Ba” ranking indicates an obligation that is judged to have speculative elements and is subject to substantial credit risk. A “B” rating from Moody’s signifies an obligation that is considered speculative and is subject to high credit risk. The “1”, “2” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicating a mid-range ranking, and “3” ranking at the lower end of the category.

On December 10, 2004, Fitch raised our senior unsecured rating to BB from B+ and revised the ratings outlook to stable from positive. With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. A “BB” rating from Fitch indicates that there is a possibility of credit risk developing, particularly as the result of adverse economic change over time; however, business or financial alternatives may be available to allow financial commitments to be met. Fitch may add a “+” or a “— ” sign to show the obligor’s relative standing within a major rating category.

As our financial ratios improve and we continue to reduce debt in line with forecasts, our ratings could improve. Improved ratings could result in lower borrowing costs. However, if our financial ratios do not meet expected levels, the outlook and the rating could decline.

Our historical debt to capitalization ratios and our forecasted amount for 2005 are shown below.


							Expected
	2002		2003		2004		2005

Debt to Capitalization*		72.3%		74.5%		61.6%		59%-60%


*	Debt includes Long-term debt and Long-term debt due within one year. Capitalization includes debt as calculated above plus Stockholders’ equity.


	Off-balance sheet financing arrangements and guarantees of debt or other commitments to third parties

As discussed in Sources of liquidity, in April 2004, we entered into two unsecured bank revolving credit facilities totaling $500 million. We were able to obtain the unsecured credit facilities because the funding bank syndicated its associated credit risk into the institutional investor market. Upon the occurrence of certain credit events, letters of credit outstanding under the agreement become cash collateralized, creating a borrowing under the facilities. Concurrently, the bank can deliver the facilities to the institutional investors, whereby the investors replace the bank as lender under the facilities.

To facilitate the syndication of the facilities, the bank established trusts funded by the institutional investors. The assets of the trusts serve as collateral to reimburse the bank for our borrowings in the event the facilities are delivered to the investors. We have no asset securitization or collateral requirements under the new facilities. During the second quarter, use of these new facilities released approximately $496 million of restricted cash, restricted investments and margin deposits. In January 2005, these facilities were terminated and replaced with two new facilities that contain similar terms but fewer restrictions (see Note 11 of Notes to the Consolidated Financial Statements).

We have various guarantees which are disclosed in Notes 3, 10, 11, 14 and 15 of Notes to Consolidated Financial Statements. We do not believe these guarantees or the possible fulfillment of them will negatively impact our liquidity.


	*Operating activities*

The increase in cash flow from operations from 2003 to 2004 is primarily due to:


	•	the increase in cash flow from changes in accounts payable of $512 million,

	•	the increase in cash flow from changes in derivatives and energy risk management and trading assets and liabilities of $190 million,

	•	the reduction of margin deposit requirements of $170 million, and

	•	the improvement in Income (loss) from continuing operations of $151 million.

Lower margin deposit funding requirements in 2004, facilitated by letter of credit issues, resulted in higher cash inflow in 2004. In addition, positive cash flows resulting from the settlement of derivative contracts contributed to higher cash inflow primarily from Power in 2004.

The increase in cash flows from operations were largely offset by a decrease in cash flow from changes in accounts receivable of $434 million, due primarily to the operation of Power’s managed assets.

Additionally, on November 1, 2004, Winterthur remitted approximately $85 million to us in the settlement of certain disputes regarding insurance obligations under construction contracts (see Note 4 of Notes to Consolidated Financial Statements).

The increase in funds from noncurrent restricted cash of $124.5 million in 2004 is primarily due to the release of cash held as collateral for various surety bonds.

We recorded approximately $86.7 million, $231.9 million and $399.1 million in provisions for losses on property and other assets in 2004, 2003, and 2002, respectively. We also recorded net gain on disposition of assets of $18.1 million, $142.8 million, and $190.4 million, in 2004, 2003, and 2002, respectively (see Notes 3 and 4 of Notes to Consolidated Financial Statements).

In 2003, we recorded an accrual for fixed rate interest included in the secured note payable of Williams Production RMT company (the RMT Note) on the Consolidated Statement of Cash Flows representing the quarterly non-cash reclassification of the deferred fixed rate interest from an accrued liability to the RMT Note. The Amortization of deferred set-up fee and fixed rate interest on the RMT Note relates to amounts recognized in the Consolidated Statement of Operations as interest expense, but which were not payable until maturity. The RMT Note was repaid in May 2003.

In March 2002, WilTel exercised its option to purchase certain network assets under a transaction for which we had previously provided a guarantee. On March 29, 2002, as guarantor under the agreement, we paid $753.9 million related to WilTel’s purchase of these network assets.

Other, including changes in noncurrent assets and liabilities, includes contributions to our tax qualified pension plans of $136.8 million, $42.8 million and $77.0 million in 2004, 2003 and 2002, respectively. It is our policy to fund our tax qualified pension plans the greater of the actuarially computed annual normal cost plus any unfunded actuarial accrued liability, amortized over approximately five years, or the minimum required contribution under existing tax laws. Additional amounts may be contributed to increase the funded status of the plans. In an effort to strengthen our funded status and take advantage of very strong cash flows, we contributed approximately $98.9 million more than our funding policy required in 2004.


	*Financing activities*

During 2004, we made significant progress on our plan to reduce debt. We retired approximately $4 billion of debt through scheduled maturities, early debt retirements, and an exchange offer on our FELINE PACS units. In 2005, scheduled maturities are approximately $247 million. Significant reductions in debt during 2004 include the following.


	•	On March 15, we retired the remaining $679 million outstanding balance of the 9.25 percent senior unsecured notes due March 15, 2004.

	•	In June and September, we retired a total of approximately $2 billion through tender offers. In May we also repurchased on the open market approximately $255 million of various notes. In conjunction with the tendered notes, related consents, and the debt repurchase, we paid premiums of approximately $214 million. The premiums, as well as related fees and expenses, together totaling $252.4 million, are included in Early debt retirement costs on the Consolidated Statement of Cash Flows.

	•	In June, we made a payment of approximately $109 million for accrued interest, short-term payables, and long-term debt on borrowings collateralized by certain receivables from the California Power Exchange that were previously sold to a third party. Approximately $79 million of the

payment is included in Payments of long-term debt on the Consolidated Statement of Cash Flows. In July 2004, we received payment of approximately $104 million from the California Power Exchange which is reported in Changes in accounts and notes receivable on the Consolidated Statement of Cash Flows.

• In October, we completed the exchange of approximately 33.1 million FELINE PACS units for one share of our common stock plus $1.47 in cash for each unit resulting in the retirement of $827 million of debt.

• In November, we completed the purchase and retirement of approximately $200 million of the remaining notes in connection with our FELINE PACS remarketing. Approximately $73.1 million of the original $1.1 billion of notes remains outstanding and is due on February 16, 2007.

For additional discussion of other repayments in 2004, see Note 11 of Notes to Consolidated Financial Statements.

We made significant reductions in our debt in 2003. We retired $3.2 billion in debt, redeemed $275 million in preferred stock, and issued $2 billion in debt at more favorable market rates.

Significant borrowings and repayments during 2003 included the following.


	•	On March 4, our Northwest Pipeline subsidiary completed an offering of $175 million of 8.125 percent senior notes due 2010. Proceeds from the issuance were used for general corporate purposes, including the funding of capital expenditures.

	•	On May 28, we issued $300 million of 5.5 percent junior subordinated convertible debentures due 2033. The proceeds were used to redeem all outstanding 9.875 percent cumulative-convertible preferred shares.

	•	In May, we repaid the RMT Note totaling $1.15 billion, which included certain contractual fees and deferred interest.

	•	On May 30, a subsidiary in our Exploration & Production segment entered into a $500 million secured note due May 30, 2007, at a floating interest rate of LIBOR plus 3.75 percent. This loan refinanced a portion of the RMT Note discussed above. On February 25, 2004 we completed an amendment that provided more favorable terms including a lower interest rate and an extension of the maturity by one year.

	•	On June 6, we entered into a two-year $800 million revolving and letter of credit facility, primarily for the purpose of issuing letters of credit. The facility was secured by cash and/or acceptable government securities. We terminated this facility in May 2004.

	•	On June 10, we issued $800 million of 8.625 percent senior unsecured notes due 2010. The notes were issued under our $3 billion shelf registration statement. The proceeds were used to improve corporate liquidity, general corporate purposes, and payment of maturing debt obligations. We retired $793 million of these notes in an August 2004 tender offer.

	•	On June 10, we also redeemed all the outstanding 9.875 percent cumulative-convertible preferred shares for approximately $289 million, plus $5.3 million for accrued dividends.

	•	In October, we retired $721 million of senior unsecured 9.25 percent notes and $230 million of other notes and debentures through tender offers. In conjunction with the tendered notes and related consents, we paid premiums of approximately $58 million. The premiums, as well as related fees and expenses, together totaling $66.8 million, are included in Early debt retirement costs on the Consolidated Statement of Cash Flows.

	•	In October, our PIGAP high-pressure gas compression project in Venezuela obtained $230 million in non-recourse financing. We own a 70 percent interest in the project and, therefore, the debt is reflected on our Consolidated Balance Sheet. Proceeds from the loan were used to repay us for notes due and the other owner for a portion of the initial funding of construction-related costs. Upon the

execution of the loan, the project made additional cash distributions to the owners based on their respective ownership interests. We received approximately $183 million in cash proceeds, net of amounts paid relating to an up front premium, the purchase of an interest rate lock and cash used to fund a debt service reserve.

Significant borrowings and repayments in 2002 included the following.


	•	On January 14, we completed the sale of 44 million publicly traded units, known as FELINE PACS, that include a senior debt security and an equity purchase contract, for net proceeds of approximately $1.1 billion. As discussed previously, only $73.1 million of notes remains outstanding at December 31, 2004.

	•	On March 19, we issued $850 million of 30-year notes with an interest rate of 8.75 percent and $650 million of 10-year notes with an interest rate of 8.125 percent. The proceeds were used to repay approximately $1.4 billion outstanding commercial paper, provide working capital and for general corporate purposes.

	•	In May, Power entered into an agreement which transferred the rights to certain receivables, along with risks associated with that collection, in exchange for cash. Due to the structure of the agreement, Power accounted for this transaction as debt collateralized by the claims and recorded $79 million of debt. As discussed previously, this amount was paid in June 2004.

	•	RMT entered into a $900 million credit agreement dated as of July 31, 2002. As discussed previously, this amount was repaid in May 2003.

Dividends paid on common stock were increased from $.01 to $.05 per common share in fourth-quarter 2004 and totaled $43.4 million for the year ended 2004. One of the covenants under the former $500 million revolving credit facilities limited our quarterly common stock dividends to not more than $.05 per common share. The covenant was removed when the facilities were replaced on January 20, 2005.

In 2003, we also paid $32.6 million in accrued dividends on the 9.875 percent cumulative-convertible preferred shares that were redeemed in June 2003. The $32.6 million of preferred dividends paid includes the 2003 payment of $6.8 million in dividends accrued at December 31, 2002. The $29.5 million of preferred stock dividends reported on the Consolidated Statement of Operations also includes $3.7 million of issuance costs.

During 2002, structural changes to certain limited liability company member interests required classification of these outside investor interests as debt. These structural changes also included the repayment of the investor’s preferred interest in installments. During 2002, approximately $558 million was repaid related to these interests and is included in the payments of long-term debt. During 2003, the remaining balances associated with these interests were paid. Approximately $323 million of payments are included in payments of long-term debt for 2003.

In third-quarter 2002, the downgrade of our senior unsecured rating below BB by Standard & Poor’s, and Ba1 by Moody’s Investors Service, resulted in the early retirement of an outside investor’s preferred ownership interest for $135 million.

Significant items reflected as discontinued operations within financing activities in the Consolidated Statement of Cash Flows, including the cash provided by financing activities, include the following items:


	•	proceeds from long-term debt of Williams Energy Partners LP related to financing entered into in 2002 of $489 million, and

	•	net proceeds from issuance of common units by Williams Energy Partners LP in 2002 of $279 million.


	*Investing activities*

Capital expenditures by segment are presented below.

Capital Expenditures


Segment		2004		2003		2002

		(Millions)
Power		$	1.0	$	1.0	$	135.8
Gas Pipeline			251.0		497.6		672.0
E&P			445.4		202.0		364.1
Midstream			84.2		252.9		432.8
Other			5.8		2.5		57.3

	Total	$	787.4	$	956.0	$	1,662.0


	•	Power made capital expenditures in 2002 primarily to purchase power-generating turbines.

	•	Gas Pipeline made capital expenditures in 2004 primarily for the maintenance of existing facilities and in 2002 through 2003 primarily to expand deliverability into the east and west coast markets. Planned expenditures for 2005 are primarily for the maintenance of existing facilities and certain regulatory compliance measures.

	•	Exploration & Production made capital expenditures in 2002 through 2004 primarily for continued development of our natural gas reserves through the drilling of wells. Planned expenditures for 2005 are focused on increasing production from our portfolio of undeveloped reserves and pursuing expansion opportunities in existing and new basins.

	•	Midstream made capital expenditures in 2002 through 2004 primarily to acquire, expand, develop and modernize gathering and processing facilities and terminals. Included in capital expenditures are the following amounts related to the deepwater project: 2004 — $31 million; 2003 — $189 million; and 2002 — $343 million. Planned expenditures for 2005 are focused on attracting new volumes to our assets and further expanding our systems in existing basins.

In September 2004, we received a $67.9 million payment from WilTel, which included payment in full on the balance of our short-term note receivable of $54.6 million and a principal payment on the long-term note receivable in the amount of $13.3 million. This activity is included in Payments received on notes receivable from WilTel on the Consolidated Statement of Cash Flows. In December 2004, we reached an agreement to sell the remaining balance of the WilTel Note. In January 2005, the sale closed and we received approximately $54.6 million.

During the first four months of 2004, we purchased $471.8 million of restricted investments comprised of U.S. Treasury notes and received proceeds of $851.4 million on the scheduled maturity of certain of this type investment. We made these purchases to satisfy the 105 percent cash collateralization requirement in the $800 million revolving credit facility. This facility was terminated on May 3, 2004, after we obtained the $1 billion secured revolving credit facility, amended to $1.275 billion in August 2004 (see Note 11 of Notes to Consolidated Financial Statements). In 2003, we purchased $739.9 million of restricted investments comprised of U.S. Treasury notes. We sold $10 million of these notes and retired $341.8 million on their scheduled maturity date.

During February 2004, we participated in a recapitalization plan completed by Longhorn. As a result of this plan, we received approximately $58 million in repayment of a portion of our advances to and deferred payments from Longhorn and converted the remaining advances, including accrued interest, into preferred equity interests in Longhorn. The $58 million received is included in Proceeds from dispositions of investments and other assets.

Purchase of investments/advances to affiliates in 2003 consists primarily of $127 million of additional investment by Midstream in Discovery. The cash investment was used by Discovery to pay maturing debt (see Note 3 of Notes to Consolidated Financial Statements). Purchases in 2002 include approximately $234 million towards the development of the Gulfstream joint venture project, one of our equity method investments.

In 2004, 2003 and 2002, we realized significant cash proceeds from asset dispositions, the sales of businesses, and the disposition of investments as part of our overall plan to increase liquidity and reduce debt. The following sales provided significant proceeds and include various adjustments subsequent to the actual date of sale:


	In 2004:


	•	approximately $544 million in net proceeds related to the sale of our Canadian straddle plants; and

	•	$305 million related to the sale of Alaska refinery, retail and pipeline and related assets.


	In 2003:


	•	$803 million related to the sale of Texas Gas Transmission Corporation;

	•	$465 million related to the sale of certain natural gas exploration and production properties in Kansas, Colorado, New Mexico and Utah;

	•	$455 million (net of cash held by Williams Energy Partners) related to the sale of our general partnership interest and limited partner investment in Williams Energy Partners;

	•	$452 million related to the sale of the Midsouth refinery;

	•	$246 million related to the sale of certain natural gas liquids assets in Redwater, Alberta; and

	•	$188 million related to the sale of the Williams travel centers.


	In 2002:


	•	$1.15 billion related to the sale of Mid-American and Seminole Pipeline;

	•	$464 million related to the sale of Kern River;

	•	$380 million related to the sale of Central;

	•	$326 million related to the sale of properties in the Jonah Field and the Anadarko Basin;

	•	$229 million related to the sale of the Cove Point LNG facility; and

	•	$173 million related to the sale of our interest in Alliance Pipeline.

In fourth-quarter 2002, we received $180 million in cash proceeds from the sale of notes receivable from WilTel to Leucadia.

Significant items reflected as discontinued operations within investing activities on the Consolidated Statement of Cash Flows include capital expenditures of Texas Gas, primarily for expansion of its interstate natural gas pipeline system, of $41.9 million in 2002.


	Outlook for 2005 and beyond

We enter 2005 having completed our restructuring plan and are now in a position to shift to growth through disciplined investments in natural gas businesses. In 2005, we expect to continue to reduce debt, although not at the levels experienced in the last year. As noted previously, we expect to maintain liquidity from cash and revolving credit facilities of at least $1 billion. We are maintaining this level as we consider the potential impact of significant changes in commodity prices, contract margin requirements above current levels, unplanned capital spending needs and the need to meet near term scheduled debt payments.

As of December 31, 2004, our two unsecured revolving credit facilities contained covenants that restricted our ability to issue new debt, with minimal exceptions, until a certain fixed charge coverage ratio was achieved. In January 2005, these facilities were terminated and replaced with two new facilities from which most of the restrictive covenants, including this fixed charge ratio, were removed.

As a result of our growth, we estimate capital and investment expenditures will increase in the future to approximately $1 billion to $1.2 billion in 2005. Of the estimated capital expenditures for 2005, approximately $610 million to $695 million is for maintenance related projects primarily at Gas Pipeline, including pipeline replacement and Clean Air Act projects. We expect to fund capital and investment expenditures, debt payments, and working-capital requirements through cash and cash equivalents on hand and cash generated from operations, which is currently estimated to be between $1.3 billion and $1.6 billion in 2005.

Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include.


	•	Lower than expected levels of cash flow from operations.


	To mitigate this exposure, Exploration & Production has economically hedged the price of natural gas for approximately 286 MMcfe per day of its expected 2005 production of 600 to 700 MMcfe per day. Power estimates that it has economically hedged revenues, of varying degrees of certainty, covering approximately 97 percent of its fixed demand obligations through 2010.


	•	Sensitivity of margin requirements associated with our marginable commodity contracts.


	As of December 2004, we estimate our exposure to additional margin requirements over the next 360 days to no more than $353 million.


	•	Exposure associated with our efforts to resolve regulatory and litigation issues (see Note 15 of Notes to Consolidated Financial Statements).

Based on our available cash on hand and expected cash flows from operations, we believe we have, or have access to, the financial resources and liquidity necessary to meet future cash requirements and maintain a sufficient level of liquidity to reasonably protect against unforeseen circumstances requiring the use of funds.


	*Contractual obligations*

The table below summarizes the maturity dates of our contractual obligations by period.


				2006-		2008-
		2005		2007		2009		Thereafter			Total

		(Millions)
Long-term debt, including current portion:
	Principal	$	247	$	515	$	769	$	6,457		$	7,988
	Interest		574		1,124		1,014		6,562			9,274
Capital leases			—		—		—		—			—
Operating leases(1)(5)			194		379		367		1,412			2,352
Purchase obligations:
	Fuel conversion and other service contracts(2)(5)		239		490		501		2,844			4,074
	Other(5)		400		446		312		454	(4)		1,612
Other long-term liabilities, including current portion:
	Physical & financial derivatives:(3)(5)		564		301		178		189			1,232
	Other(5)		47		80		30		16			173

Total		$	2,265	$	3,335	$	3,171	$	17,934		$	26,705


(1)	Excludes sublease income of $875 million consisting of $168 million in 2005, $334 million in 2006-2007, $250 million in 2008-2009 and $123 million thereafter. Includes a Power tolling agreement that is now accounted for as an operating lease as a result of our implementation of EITF Issue No. 01-8, “Determining Whether An Arrangement Contains a Lease,” (EITF 01-8). This agreement was previously included in fuel conversion and other service contracts within purchase obligations. See Note 11 of Notes to Consolidated Financial Statements for additional information.

(2)	Power has entered into certain contracts giving us the right to receive fuel conversion services as well as certain other services associated with electric generation facilities that are currently in operation throughout the continental United States.

(3)	Although the amounts presented represent expected cash outflows, a portion of those obligations have previously been paid in accordance with third party margining agreements. As of December 31, 2004, we have paid $72 million in margins, adequate assurance, and prepays related to the obligations included in this disclosure. In addition, the obligations for physical and financial derivatives are based on market information as of December 31, 2004. Because market information changes daily and has the potential to be volatile, significant changes to the values in this category may occur.

(4)	Includes one year of annual payments totaling $2 million for contracts with indefinite termination dates.

(5)	Expected offsetting cash inflows resulting from product sales or net positive settlements are not reflected in these amounts. The offsetting expected cash inflows as of December 31, 2004 are $5 billion.

Effects of inflation

Our operations in recent years have benefited from relatively low inflation rates. Approximately 49 percent of our gross property, plant and equipment is at Gas Pipeline and approximately 51 percent is at other operating units. Gas Pipeline is subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to replace existing assets. Cost based regulation, along with competition and other market factors, may limit our ability to recover such increased costs. For the other operating units, operating costs are influenced to a greater extent by specific price changes in oil and natural gas and related commodities than by changes in general inflation. Crude,

refined product, natural gas, natural gas liquids and power prices are particularly sensitive to OPEC production levels and/or the market perceptions concerning the supply and demand balance in the near future.

Environmental

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and/or remedial processes at certain sites, some of which we currently do not own (see Note 15 of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $72 million, all of which are recorded as liabilities on our balance sheet at December 31, 2004. We expect to seek recovery of approximately $23 million of the accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2004, we paid approximately $10 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $14 million in 2005 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. At December 31, 2004, certain assessment studies were still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

We are subject to the federal Clean Air Act and to the federal Clean Air Act Amendments of 1990 which require the EPA to issue new regulations. We are also subject to regulation at the state and local level. In September 1998, the EPA promulgated rules designed to mitigate the migration of ground-level ozone in certain states. In March 2004 and June 2004, the EPA promulgated additional regulation regarding hazardous air pollutants which may impose additional controls. Capital expenditures necessary to install emission control devices on our Transco gas pipeline system to comply with rules were approximately $62 million in 2004 and are estimated to be between $110 million and $125 million over the next three years. This estimate of remaining expenditures is more than 50 percent lower than previous estimates due to 2004 expenditures, further analysis of the requirements, and also more clarification and finalization of government regulations. The actual costs incurred will depend on the final implementation plans developed by each state to comply with these regulations. We consider these costs on our Transco system associated with compliance with these environmental laws and regulations to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through its rates.


Item 7A.	*Qualitative and Quantitative Disclosures About Market Risk*

Interest rate risk

Our current interest rate risk exposure is related primarily to our debt portfolio, which was significantly reduced in 2004 by early retirements and payments. We reduced our total long-term debt, including current portion, from approximately $12 billion at December 31, 2003, to approximately $8 billion at December 31, 2004 (see Note 11 of Notes to Consolidated Financial Statements).

The majority of our debt portfolio is comprised of fixed rate debt in order to mitigate the impact of fluctuations in interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected life of our operating assets.

The tables below provide information as of December 31, 2004 and 2003, about our interest rate risk sensitive instruments. Long-term debt in the tables represents principal cash flows, net of (discount) premium, and weighted-average interest rates by expected maturity dates.


																						Fair Value
																						December 31,
		2005			2006			2007			2008			2009			Thereafter			Total		2004

		(Dollars in millions)
Long-term debt, including current portion:
	Fixed rate	$	235		$	104		$	381		$	153		$	41		$	6,386		$	7,300	$	8,167
	Interest rate		7.6	%		7.7	%		7.7	%		7.7	%		7.7	%		7.7	%
	Variable rate	$	15		$	15		$	15		$	563		$	12		$	42		$	662	$	675
	Interest rate(1)


																						Fair Value
																						December 31,
		2004			2005			2006			2007			2008			Thereafter			Total		2003

		(Dollars in millions)
Long-term debt, including current portion:
	Fixed rate	$	841		$	232		$	957		$	1,527		$	374		$	7,362		$	11,293	$	11,574
	Interest rate		7.5	%		7.5	%		7.5	%		7.7	%		7.8	%		7.7	%
	Variable rate	$	94		$	15		$	15		$	493		$	11		$	54		$	682	$	709
	Interest rate(2)
Marketable securities:
	Notional amount(3)	$	379		$	—		$	—		$	—		$	—		$	—		$	379	$	381
	Fixed rate		3.5	%


(1)	The weighted-average interest rate for 2004 is LIBOR plus 2.3 percent.

(2)	The weighted-average interest rate for 2003 was LIBOR plus 3.75 percent.

(3)	The marketable equity securities matured in 2004. The Consolidated Balance Sheet classification was determined based on the expected term of the underlying collateral requirement.

Commodity price risk

We are exposed to the impact of market fluctuations in the price of natural gas, power, crude oil, refined products and natural gas liquids and additionally to other market factors, such as market volatility and commodity price correlations, including correlations between crude oil and gas prices and between natural gas and power prices. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts and our proprietary trading activities. We manage the risks associated with these market fluctuations using various derivatives. The fair value of derivative contracts is subject to changes in energy-commodity market prices, the liquidity and volatility of the markets in which the contracts are

transacted, and changes in interest rates. We measure the risk in our portfolios using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolios.

Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolios. The value-at-risk model assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolios will not exceed the value at risk. Beginning in 2004, the value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues. In 2003, the value at risk model used historical simulations to estimate hypothetical movements in future market prices, assuming normal market conditions and historical market prices. In applying both value-at-risk methodologies, we do not consider that changing the portfolio in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.

We segregate our derivative contracts into trading and non-trading contracts, as defined in the following paragraphs. We calculate value at risk separately for these two categories. Derivative contracts designated as normal purchases or sales under SFAS 133 and non-derivative energy contracts have been excluded from our estimation of value at risk.


	*Trading*

Our trading portfolio consists of derivative contracts entered into to provide price risk management services to third-party customers. Only contracts that meet the definition of a derivative are carried at fair value on the balance sheet. Our value at risk for contracts held for trading purposes was $1 million at December 31, 2004 and $5 million at December 31, 2003. During the year ended December 31, 2004, our value at risk for these contracts ranged from a high of $3 million to a low of $1 million.


	*Non-Trading*

Our non-trading portfolio consists of contracts that hedge or could potentially hedge the price risk exposure from the following activities:


Segment		Commodity Price Risk Exposure

Exploration & Production		• Natural gas sales

Midstream		• Natural gas purchases

Power		• Natural gas purchases
		• Electricity purchases
		• Electricity sales

The value at risk for contracts held for non-trading purposes was $29 million and $18 million at December 31, 2004 and 2003, respectively. During the year ended December 31, 2004, our value at risk for these contracts ranged from a high of $29 million to a low of $18 million. Certain of the contracts held for non-trading purposes were accounted for as cash flow hedges under SFAS 133. We did not consider the underlying commodity positions to which the cash flow hedges relate in our value-at-risk model. Therefore, value at risk does not represent economic losses that could occur on a total non-trading portfolio that includes the underlying commodity positions.

Foreign currency risk

We have international investments that could affect our financial results if the investments incur a permanent decline in value as a result of changes in foreign currency exchange rates and the economic conditions in foreign countries.

International investments accounted for under the cost method totaled $52 million and $95 million at December 31, 2004, and 2003, respectively. These investments are primarily in non-publicly traded companies for which it is not practicable to estimate fair value. We believe that we can realize the carrying value of these investments considering the status of the operations of the companies underlying these investments. If a 20 percent change occurred in the value of the underlying currencies of these investments against the U.S. dollar, the fair value at December 31, 2004, could change by approximately $10 million assuming a direct correlation between the currency fluctuation and the value of the investments.

The sale of our Canadian straddle plants in July 2004 decreased our exposure to foreign currency risk. Net assets of consolidated foreign operations whose functional currency is the local currency are located primarily in Canada and approximate six percent of our net assets at December 31, 2004, compared to 15 percent of our net assets at December 31, 2003. These foreign operations do not have significant transactions or financial instruments denominated in other currencies. However, these investments do have the potential to impact our financial position, due to fluctuations in these local currencies arising from the process of re-measuring the local functional currency into the U.S. dollar. As an example, a 20 percent change in the respective functional currencies against the U.S. dollar could have changed stockholders’ equity by approximately $64 million at December 31, 2004.

We historically have not utilized derivatives or other financial instruments to hedge the risk associated with the movement in foreign currencies with the exception of a Canadian dollar-denominated note receivable which was terminated in 2004 (see Note 14 of Notes to Consolidated Financial Statements). However, we monitor currency fluctuations and could potentially use derivative financial instruments or employ other investment alternatives if cash flows or investment returns so warrant.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER

FINANCIAL REPORTING

Williams management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) and for the assessment of the effectiveness of internal control over financial reporting. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

All internal control systems, no matter how well designed have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management assessed the effectiveness of Williams’ internal control over financial reporting as of December 31, 2004. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of our internal control over financial reporting. Based on our assessment we believe that, as of December 31, 2004, Williams’ internal control over financial reporting is effective based on those criteria.

Ernst & Young, LLP, our independent registered public accounting firm has issued an audit report on our assessment of the company’s internal control over financial reporting. A copy of this report is included in this Annual Report on Form 10-K.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING

FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Board of Directors and Stockholders of

The Williams Companies, Inc.

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that The Williams Companies, Inc. maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Williams Companies, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that The Williams Companies, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, The Williams Companies, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of The Williams Companies, Inc. as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2004 of The Williams Companies, Inc. and our report dated March 8, 2005 expressed an unqualified opinion thereon.

Tulsa, Oklahoma

March 8, 2005


Item 8.	*Financial Statements and Supplementary Data*

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of

The Williams Companies, Inc.

We have audited the accompanying consolidated balance sheet of The Williams Companies, Inc. as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedule listed in the index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of The Williams Companies, Inc. at December 31, 2004 and 2003, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As explained in Note 1 and Note 9 to the consolidated financial statements, effective January 1, 2003, the Company adopted Emerging Issues Task Force Issue No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (see third paragraph of “Energy commodity risk management and trading activities and revenues” section in Note 1) and Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (see the penultimate paragraph of Note 9).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of The Williams Companies, Inc.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion thereon.

Tulsa, Oklahoma

March 8, 2005

THE WILLIAMS COMPANIES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS


			Years Ended December 31,

			2004			2003			2002

			(Millions, except per-share amounts)
Revenues:
	Power		$	9,272.4		$	13,195.5		$	56.2
	Gas Pipeline			1,362.3			1,368.3			1,301.2
	Exploration & Production			777.6			779.7			860.4
	Midstream Gas & Liquids			2,882.6			2,784.8			1,183.7
	Other			32.8			72.0			124.1
	Intercompany eliminations			(1,866.4	)		(1,549.3	)		(91.1	)

		Total revenues		12,461.3			16,651.0			3,434.5

Segment costs and expenses:
	Costs and operating expenses			10,751.7			15,004.3			1,987.7
	Selling, general and administrative expenses			355.5			421.3			575.6
	Other (income) expense — net			(51.6	)		(21.3	)		240.4

		Total segment costs and expenses		11,055.6			15,404.3			2,803.7

General corporate expenses				119.8			87.0			142.8

Operating income (loss):
	Power			86.5			145.3			(471.7	)
	Gas Pipeline			557.6			539.6			461.3
	Exploration & Production			223.9			392.5			504.9
	Midstream Gas & Liquids			552.2			178.0			153.2
	Other			(14.5	)		(8.7	)		(16.9	)
	General corporate expenses			(119.8	)		(87.0	)		(142.8	)

		Total operating income		1,285.9			1,159.7			488.0

Interest accrued				(834.4	)		(1,293.5	)		(1,169.2	)
Interest capitalized				6.7			45.5			27.3
Interest rate swap loss				(5.0	)		(2.2	)		(124.2	)
Investing income (loss)				48.0			73.2			(113.1	)
Early debt retirement costs				(282.1	)		(66.8	)		—
Minority interest in income and preferred returns of consolidated subsidiaries				(21.4	)		(19.4	)		(41.8	)
Other income — net				26.8			40.7			24.3

Income (loss) from continuing operations before income taxes and cumulative effect of change in accounting principles				224.5			(62.8	)		(908.7	)
Provision (benefit) for income taxes				131.3			(5.3	)		(290.3	)

Income (loss) from continuing operations				93.2			(57.5	)		(618.4	)
Income (loss) from discontinued operations				70.5			326.6			(136.3	)

Income (loss) before cumulative effect of change in accounting principles				163.7			269.1			(754.7	)
Cumulative effect of change in accounting principles				—			(761.3	)		—

Net income (loss)				163.7			(492.2	)		(754.7	)
Preferred stock dividends				—			29.5			90.1

Income (loss) applicable to common stock			$	163.7		$	(521.7	)	$	(844.8	)

Basic earnings (loss) per common share:
	Income (loss) from continuing operations		$	.18		$	(.17	)	$	(1.37	)
	Income (loss) from discontinued operations			.13			.63			(.26	)

	Income (loss) before cumulative effect of change in accounting principles			.31			.46			(1.63	)
	Cumulative effect of change in accounting principles			—			(1.47	)		—

		Net income (loss)	$	.31		$	(1.01	)	$	(1.63	)

Diluted earnings (loss) per common share:
	Income (loss) from continuing operations		$	.18		$	(.17	)	$	(1.37	)
	Income (loss) from discontinued operations			.13			.63			(.26	)

	Income (loss) before cumulative effect of change in accounting principles			.31			.46			(1.63	)
	Cumulative effect of change in accounting principles			—			(1.47	)		—

		Net income (loss)	$	.31		$	(1.01	)	$	(1.63	)

See accompanying notes.

THE WILLIAMS COMPANIES, INC.

CONSOLIDATED BALANCE SHEET


			December 31,

			2004			2003

			(Dollars in millions,
			except per-share
			amounts)
ASSETS
Current assets:
	Cash and cash equivalents		$	930.0		$	2,315.7
	Restricted cash			77.4			47.1
	Restricted investments			—			93.2
	Accounts and notes receivable less allowance of $98.8 ($112.2 in 2003)			1,422.8			1,613.2
	Inventories			261.1			242.9
	Derivative assets			2,961.0			3,166.8
	Margin deposits			131.7			553.9
	Assets of discontinued operations			13.6			381.2
	Deferred income taxes			89.0			106.6
	Other current assets and deferred charges			157.0			274.4

		Total current assets		6,043.6			8,795.0
Restricted cash				35.3			159.8
Restricted investments				—			288.1
Investments				1,316.2			1,463.6
Property, plant and equipment — net				11,886.8			11,734.0
Derivative assets				3,025.3			2,495.6
Goodwill				1,014.5			1,014.5
Assets of discontinued operations				—			345.1
Other assets and deferred charges				671.3			726.1

		Total assets	$	23,993.0		$	27,021.8


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Notes payable		$	—		$	3.3
	Accounts payable			1,043.2			1,186.8
	Accrued liabilities			991.7			987.9
	Liabilities of discontinued operations			1.6			93.4
	Derivative liabilities			2,859.3			3,064.2
	Long-term debt due within one year			250.1			935.2

		Total current liabilities		5,145.9			6,270.8
Long-term debt				7,711.9			11,039.8
Deferred income taxes				2,470.1			2,453.4
Derivative liabilities				2,735.7			2,124.1
Other liabilities and deferred income				873.8			947.5
Contingent liabilities and commitments (Note 15)
Minority interests in consolidated subsidiaries				99.7			84.1
Stockholders’ equity:
	Common stock, $1 per share par value, 960 million shares authorized, 561.2 million issued in 2004, 521.4 million issued in 2003			561.2			521.4
	Capital in excess of par value			6,005.9			5,195.1
	Accumulated deficit			(1,306.5	)		(1,426.8	)
	Accumulated other comprehensive loss			(244.2	)		(121.0	)
	Other			(21.9	)		(28.0	)

				4,994.5			4,140.7
	Less treasury stock (at cost), 3.2 million shares of common stock in 2004 and 2003			(38.6	)		(38.6	)

		Total stockholders’ equity		4,955.9			4,102.1

		Total liabilities and stockholders’ equity	$	23,993.0		$	27,021.8

See accompanying notes.

THE WILLIAMS COMPANIES, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY


															Accumulated
									Capital in						Other
									Excess of			Retained			Comprehensive
				Preferred			Common		Par			Earnings			Income						Treasury
				Stock			Stock		Value			(Deficit)			(Loss)			Other			Stock			Total

				(Dollars in millions)
Balance, December 31, 2001				$	—		$	518.9	$	5,085.1		$	199.6		$	345.1		$	(65.0	)	$	(39.7	)	$	6,044.0
Comprehensive loss:
	Net loss — 2002				—			—		—			(754.7	)		—			—			—			(754.7	)
Other comprehensive loss:
		Net unrealized losses on cash flow hedges, net of reclassification adjustments			—			—		—			—			(298.9	)		—			—			(298.9	)
		Net unrealized appreciation on marketable equity securities, net of reclassification adjustments			—			—		—			—			4.6			—			—			4.6
		Foreign currency translation adjustments			—			—		—			—			(.1	)		—			—			(.1	)
		Minimum pension liability adjustment			—			—		—			—			(16.9	)		—			—			(16.9	)

	Total other comprehensive loss																								(311.3	)

Total comprehensive loss																									(1,066.0	)
Issuance of 9.875 percent cumulative convertible preferred stock (1.5 million shares)					271.3			—		—			—			—			—			—			271.3
Cash dividends — Common stock ($.42 per share)					—			—		—			(216.8	)		—			—			—			(216.8	)
			Preferred stock ($14.14 per share)		—			—		—			(20.8	)		—			—			—			(20.8	)
Issuance of equity of consolidated limited partnership					—			—		44.6			—			—			—			—			44.6
Beneficial conversion option on issuance of convertible preferred stock (Note 13)					—			—		69.4			(69.4	)		—			—			—			—
FELINE PACS equity contract adjustment (Note 13)					—			—		(76.7	)		—			—			—			—			(76.7	)
Allowance for and repayments of stockholders’ notes					—			—		—			—			—			7.8			(1.3	)		6.5
Stock award transactions, including tax benefit (1.2 million common shares)					—			1.0		33.1			—			—			.4			2.4			36.9
ESOP loan repayment					—			—		—			—			—			26.5			—			26.5
Other					—			—		21.7			(22.2	)		—			—			—			(.5	)

Balance, December 31, 2002					271.3			519.9		5,177.2			(884.3	)		33.8			(30.3	)		(38.6	)		5,049.0
Comprehensive loss:
	Net loss — 2003				—			—		—			(492.2	)		—			—			—			(492.2	)
Other comprehensive loss:
		Net unrealized losses on cash flow hedges, net of reclassification adjustments			—			—		—			—			(236.9	)		—			—			(236.9	)
		Net unrealized depreciation on marketable equity securities, net of reclassification adjustments			—			—		—			—			(7.4	)		—			—			(7.4	)
		Foreign currency translation adjustments			—			—		—			—			77.0			—			—			77.0
		Minimum pension liability adjustment			—			—		—			—			12.5			—			—			12.5

	Total other comprehensive loss																								(154.8	)

Total comprehensive loss																									(647.0	)
Redemption of 9.875 percent cumulative convertible preferred stock (1.5 million shares)					(271.3	)		—		—			—			—			—			—			(271.3	)
Cash dividends — Common stock ($.04 per share)					—			—		—			(20.8	)		—			—			—			(20.8	)
			Preferred stock ($20.14 per share)		—			—		—			(29.5	)		—			—			—			(29.5	)
Repayments of stockholders’ notes					—			—		—			—			—			2.3			—			2.3
Stock award transactions, including tax benefit (1.5 million common shares)								1.5		17.9			—			—			—			—			19.4

Balance, December 31, 2003					—			521.4		5,195.1			(1,426.8	)		(121.0	)		(28.0	)		(38.6	)		4,102.1
Comprehensive income:
	Net income — 2004				—			—		—			163.7			—			—			—			163.7
Other comprehensive loss:
		Net unrealized losses on cash flow hedges, net of reclassification adjustments			—			—		—			—			(142.7	)		—			—			(142.7	)
		Net unrealized appreciation on marketable equity securities, net of reclassification adjustments			—			—		—			—			1.9			—			—			1.9
		Foreign currency translation adjustments			—			—		—			—			15.8			—			—			15.8
		Minimum pension liability adjustment			—			—		—			—			1.8			—			—			1.8

	Total other comprehensive loss																								(123.2	)

Total comprehensive income																									40.5
Issuance of common stock (33.1 million shares) and settlement of forward contracts as a result of FELINE PACS exchange (Note 11)					—			33.1		782.9			—			—			—			—			816.0
Cash dividends — Common stock ($.08 per share)					—			—		—			(43.4	)		—			—			—			(43.4	)
Allowance for and repayment of stockholders’ notes					—			—		—			—			—			6.1			—			6.1
Stock award transactions, including tax benefit (6.7 million common shares)					—			6.7		27.9			—			—			—			—			34.6

Balance, December 31, 2004				$	—		$	561.2	$	6,005.9		$	(1,306.5	)	$	(244.2	)	$	(21.9	)	$	(38.6	)	$	4,955.9

See accompanying notes.

THE WILLIAMS COMPANIES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS


				Years Ended December 31,

				2004			2003			2002

				(Millions)
OPERATING ACTIVITIES:
	Income (loss) from continuing operations			$	93.2		$	(57.5	)	$	(618.4	)
	Adjustments to reconcile to cash provided (used) by operations:
		Depreciation, depletion and amortization			668.5			657.4			648.8
		Provision (benefit) for deferred income taxes			123.0			12.3			(212.5	)
		Payments of guarantees and payment obligations related to WilTel			—			—			(753.9	)
		Provision for loss on investments, property and other assets			86.7			231.9			399.1
		Net gain on dispositions of assets			(18.1	)		(142.8	)		(190.4	)
		Early debt retirement costs			282.1			66.8			—
		Provision for uncollectible accounts:
			WilTel		—			—			268.7
			Other		(.8	)		7.3			9.7
		Minority interest in income and preferred returns of consolidated subsidiaries			21.4			19.4			41.8
		Amortization of stock-based awards			9.5			27.1			31.2
		Payment of deferred set-up fee and fixed rate interest on RMT note payable			—			(265.0	)		—
		Accrual for fixed rate interest included in RMT note payable			—			99.3			32.2
		Amortization of deferred set-up fee and fixed rate interest on RMT note payable			—			154.5			110.9
		Cash provided (used) by changes in current assets and liabilities:
			Restricted cash		(14.1	)		(1.4	)		(4.0	)
			Accounts and notes receivable		234.6			668.7			243.7
			Inventories		(18.3	)		88.6			85.6
			Margin deposits		422.2			252.2			(633.4	)
			Other current assets and deferred charges		112.8			10.3			(264.1	)
			Accounts payable		(118.5	)		(630.2	)		(547.2	)
			Accrued liabilities		(227.0	)		(363.6	)		(285.7	)
	Changes in current and noncurrent derivative and energy risk management and trading assets and liabilities				(160.4	)		(350.0	)		579.5
	Changes in noncurrent restricted cash				86.5			17.6			(104.1	)
	Other, including changes in noncurrent assets and liabilities				(111.2	)		84.8			65.6

			Net cash provided (used) by operating activities of continuing operations		1,472.1			587.7			(1,096.9	)
			Net cash provided by operating activities of discontinued operations		15.8			182.4			581.6

			Net cash provided (used) by operating activities		1,487.9			770.1			(515.3	)

FINANCING ACTIVITIES:
	Proceeds from notes payable				—			—			913.4
	Payments of notes payable				(3.3	)		(960.8	)		(2,051.7	)
	Proceeds from long-term debt				75.0			2,006.5			3,481.5
	Payments of long-term debt				(3,263.2	)		(2,187.1	)		(2,536.2	)
	Proceeds from issuance of common stock				20.6			1.2			5.2
	Dividends paid				(43.4	)		(53.3	)		(230.8	)
	Proceeds from issuance of preferred stock				—			—			271.3
	Repurchase of preferred stock				—			(275.0	)		(135.0	)
	Payments for debt issuance costs				(26.0	)		(78.6	)		(186.3	)
	Premiums paid on early debt retirements and FELINE PACS exchange				(246.9	)		(57.7	)		—
	Payments/dividends to minority and preferred interests				(5.9	)		(19.8	)		(48.0	)
	Changes in restricted cash				21.7			67.9			(182.1	)
	Changes in cash overdrafts				(21.4	)		(29.7	)		28.4
	Other — net				(11.5	)		(2.8	)		(8.4	)

			Net cash used by financing activities of continuing operations		(3,504.3	)		(1,589.2	)		(678.7	)
			Net cash provided (used) by financing activities of discontinued operations		(1.2	)		(94.8	)		524.7

			Net cash used by financing activities		(3,505.5	)		(1,684.0	)		(154.0	)

INVESTING ACTIVITIES:
	Property, plant and equipment:
		Capital expenditures			(787.4	)		(956.0	)		(1,662.0	)
		Proceeds from dispositions			12.0			603.9			549.1
	Purchases of investments/advances to affiliates				(2.1	)		(150.4	)		(308.7	)
	Purchases of restricted investments				(471.8	)		(739.9	)		—
	Proceeds from sales of businesses				877.8			2,250.5			2,300.4
	Proceeds from sale of restricted investments				851.4			351.8			—
	Proceeds from dispositions of investments and other assets				94.1			128.6			273.0
	Proceeds received on advances to affiliates				—			—			75.0
	Proceeds received on sale of receivables from WilTel				—			—			180.0
	Payments received on notes receivable from WilTel				69.1			16.0			34.5
	Other — net				(12.9	)		15.5			(37.7	)

			Net cash provided by investing activities of continuing operations		630.2			1,520.0			1,403.6
			Net cash used by investing activities of discontinued operations		(.8	)		(23.9	)		(299.4	)

			Net cash provided by investing activities		629.4			1,496.1			1,104.2

Increase (decrease) in cash and cash equivalents					(1,388.2	)		582.2			434.9
Cash and cash equivalents at beginning of year					2,318.2			1,736.0			1,301.1

Cash and cash equivalents at end of year*				$	930.0		$	2,318.2		$	1,736.0


*	Includes cash and cash equivalents of discontinued operations of $2.5 million and $85.6 million for 2003 and 2002, respectively.

See accompanying notes.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1.	Description of business, basis of presentation and summary of significant accounting policies


	*Description of business*

Operations of our company are located principally in the United States and are organized into the following reporting segments: Gas Pipeline, Exploration & Production, Midstream Gas & Liquids, and Power.

Gas Pipeline is comprised primarily of two interstate natural gas pipelines as well as investments in natural gas pipeline-related companies. The Gas Pipeline operating segments have been aggregated for reporting purposes and include Northwest Pipeline, which extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado to Oregon and Washington, and Transcontinental Gas Pipe Line (Transco), which extends from the Gulf of Mexico region to the northeastern United States.

Exploration & Production includes natural gas development, production and gas management activities primarily in the Rocky Mountain and Mid-Continent regions of the United States and in Argentina.

Midstream Gas & Liquids (Midstream) is comprised of natural gas gathering and processing and treating facilities in the Rocky Mountain and Gulf Coast regions of the United States, oil gathering and transportation facilities in the Gulf Coast region of the United States, majority-owned natural gas compression and transportation facilities in Venezuela, and assets in Canada including a natural gas liquids extraction facility and a fractionation plant.

Power is an energy services provider that buys, sells, stores, and transports energy and energy-related commodities, primarily power and natural gas, on a wholesale level. Prior to September 2004, Power continued to focus on 1) terminating or selling all or portions of its portfolio, 2) maximizing cash flow, 3) reducing risk, and 4) managing existing contractual commitments. These efforts were consistent with our 2002 decision to sell all or portions of Power’s portfolio. In September 2004, we announced our decision to continue operating the Power business and cease efforts to exit that business. As a result, subsequent to that date, Power has focused on its objectives of minimizing financial risk, maximizing cash flow, meeting contractual commitments and providing functions that support our natural gas businesses. In addition, Power began executing new contracts to hedge its portfolio.


	*Overview*

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


	•	Completion of planned asset sales, which resulted in proceeds of approximately $877.8 million.

	•	Replacement of our cash-collateralized letter of credit and revolver facility with facilities that do not encumber cash.

	•	Significant debt reduction of approximately $4 billion of debt through scheduled maturities and early redemptions, including an exchange offer for our FELINE PACS units.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	•	Reduction of risk and liquidity requirements of the Power segment.

	•	Reduction of approximately $33 million in our combined selling, general and administrative (SG&A) and general corporate expenses.

	•	On June 1, 2004, we announced an agreement with IBM to aid us in transforming and managing certain areas of our accounting, finance and human resources processes. Under the agreement, IBM will also manage key aspects of our information technology, including enterprise wide infrastructure and application development. The 7¹/2 year agreement began July 1, 2004 and is expected to reduce costs in these areas while maintaining a high quality of service.

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


	•	the cash flow expected to be generated by the business (Power has contracts in place expected to generate cash in amounts that substantially cover its obligations through 2010);

	•	the negative effect of depressed wholesale power markets on the marketability of the Power segment; and

	•	our progress over the last two years in reducing the risk of and increasing the certainty of cash flows from long-term power contracts.

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

Our plan for 2005 includes the following objectives:


	•	increase focus and disciplined EVA®-based investments in natural gas businesses;

	•	continue to steadily improve credit ratios and ratings with the goal of achieving investment grade ratios;

	•	continue to reduce risk and liquidity requirements while maximizing cash flow in the Power segment;

	•	maintain liquidity from cash and revolving credit facilities of at least $1 billion; and

	•	generate sustainable growth in EVA® and shareholder value.

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

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

hedges. Our management, after consultation with our independent auditor, concluded that the effect of the previous accounting treatment was not material to 2003 and prior periods and the trend of earnings.


	*Basis of presentation*

In accordance with the provisions related to discontinued operations within SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the accompanying consolidated financial statements and notes reflect the results of operations, financial position and cash flows of the following components as discontinued operations (see Note 2):


	•	Kern River Gas Transmission (Kern River), previously one of Gas Pipeline’s segments;

	•	two natural gas liquids pipeline systems, Mid-American Pipeline and Seminole Pipeline, previously part of the Midstream segment;

	•	Central natural gas pipeline, previously one of Gas Pipeline’s segments;

	•	retail travel centers concentrated in the Midsouth, part of the previously reported Petroleum Services segment;

	•	refining and marketing operations in the Midsouth, including the Midsouth refinery, part of the previously reported Petroleum Services segment;

	•	Texas Gas Transmission Corporation, previously one of Gas Pipeline’s segments;

	•	natural gas properties in the Hugoton and Raton basins, previously part of the Exploration & Production segment;

	•	bio-energy operations, part of the previously reported Petroleum Services segment;

	•	general partnership interest and limited partner investment in Williams Energy Partners, previously the Williams Energy Partners segment;

	•	the Colorado soda ash mining operations, part of the previously reported International segment;

	•	certain gas processing, natural gas liquids fractionation, storage and distribution operations in western Canada and at a plant in Redwater, Alberta, previously part of the Midstream segment;

	•	refining, retail and pipeline operations in Alaska, part of the previously reported Petroleum Services segment; and

	•	straddle plants in western Canada, previously part of the Midstream segment.

During fourth-quarter 2004, we reclassified the operations of Gulf Liquids to continuing operations within our Midstream segment in accordance with EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations,” (EITF 03-13), which was issued in the fourth quarter. Under the provisions of EITF 03-13, Gulf Liquids activities no longer qualify for reporting as discontinued operations, based on management’s expectation that we will continue to have significant commercial activity with the disposed entity. The operations of Gulf Liquids were reclassified to continuing operations within our Midstream segment. All periods presented reflect this reclassification.

At December 31, 2004, the operations of Gulf Liquids are classified as held for sale and are included in Other current assets and Accrued liabilities on the balance sheet. Assets held for sale are $57 million at December 31, 2004 and $60.1 million at December 31, 2003. Liabilities held for sale are $2.2 million at December 31, 2004 and $2.3 million at December 31, 2003. Included in assets held for sale are property, plant and equipment — net of $55.3 million at December 31, 2004 and $57.8 million at December 31, 2003. We are

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

currently negotiating purchase and sale agreements related to the sale of these assets. We expect the sale of the operations to close by the end of the second quarter of 2005.

Management and decision-making control of certain activities have been transferred between segments (see Note 18). Consequently, the results of operations have been similarly reclassified. All periods presented reflect these classifications.

Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to our continuing operations.

We have restated all segment information in the Notes to the Consolidated Financial Statements for all prior periods presented to reflect discontinued operations noted above. Certain other amounts have been reclassified to conform to the current classifications.


	*Summary of significant accounting policies*


	Principles of consolidation

The consolidated financial statements include the accounts of our corporate parent and our majority-owned subsidiaries and investments. We account for companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the company, under the equity method.


	Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include:


	•	impairment assessments of investments, long-lived assets and goodwill;

	•	litigation-related contingencies;

	•	valuations of energy contracts, including energy-related contracts;

	•	environmental remediation obligations;

	•	realization of deferred income tax assets;

	•	Gas Pipeline and Power revenues subject to refund;

	•	valuation of Exploration & Production’s reserves; and

	•	pension and post retirement valuation variables.

These estimates are discussed further throughout the accompanying notes.


	Cash and cash equivalents

Cash and cash equivalents include demand and time deposits, certificates of deposit and other marketable securities with maturities of three months or less when acquired.

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Restricted cash and investments

Restricted cash within current assets at December 31, 2004, consists primarily of collateral as required by certain loan agreements for our Venezuelan operations and escrow accounts established to fund payments required by Power’s California settlement (see Note 15). Restricted cash within noncurrent assets relates primarily to certain borrowings by our Venezuelan operations and letters of credit. We do not expect this cash to be released within the next twelve months. The current and noncurrent restricted cash is primarily invested in short-term money market accounts with financial institutions.

Both short-term and long-term restricted investments at December 31, 2003 consist of short-term U.S. Treasury securities as required under the previous $800 million revolving and letter of credit facility. In the second quarter of 2004, this $800 million facility was replaced with two new unsecured revolving credit facilities totaling $500 million (see Note 11). The restricted investments held at December 31, 2003 were purchased and sold based on the balance required in the collateral account. Therefore, these securities were accounted for as “available-for-sale.” These securities were marked to market with the unrealized holding gains and losses included in Other Comprehensive Income, until realized (see Note 17). Realized gains or losses were reclassified into earnings and based on specific identification of the securities sold.

The classification of restricted cash and investments is determined based on the expected term of the collateral requirement and not necessarily the maturity date of the investment vehicle.


	Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. No allowance for doubtful accounts is recognized at the time the revenue, which generates the accounts receivable, is recognized. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is recognized at the time full payment is received or collectibility is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.


	Inventory valuation

All inventories are stated at cost, which is not in excess of market. We determined the cost of certain natural gas inventories held by Transco using the last-in, first-out (LIFO) cost method; and we determined the cost of the remaining inventories primarily using the average-cost method or market, if lower.


	Property, plant and equipment

Property, plant and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC prescribed rates. Depreciation of general plant is provided on a group basis at straight-line rates. Depreciation rates used for major regulated gas plant facilities at December 31, 2004, 2003, and 2002 are as follows:


Category of Property	Depreciation Rates

Gathering facilities		0% - 3.80%
Storage facilities		1.05% - 2.50%
Onshore transmission facilities		2.35% - 5.00%
Offshore transmission facilities		0.85% - 1.50%

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Depreciation for non-regulated entities is provided primarily on the straight-line method over estimated useful lives except as noted below regarding oil and gas exploration and production activities. The estimated useful lives are as follows:


	Estimated
Category of Property	Useful Lives

	(In years)
Natural Gas Gathering and Processing Facilities		10 to 40
Power Generation Facilities		30
Transportation Equipment		3 to 10
Building and Improvements		10 to 45
Right of Way		4 to 40
Office Furnishings & Computers		3 to 20

Gains or losses from the ordinary sale or retirement of property, plant and equipment for regulated pipelines are credited or charged to accumulated depreciation; other gains or losses are recorded in net income (loss).

Ordinary maintenance and repair costs are expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant and equipment.

Oil and gas exploration and production activities are accounted for under the successful efforts method of accounting. Costs incurred in connection with the drilling and equipping of exploratory wells, as applicable, are capitalized as incurred. If proved reserves are not found, such costs are charged to expense. Other exploration costs, including lease rentals, are expensed as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred. Unproved properties are evaluated annually, or as conditions warrant, to determine any impairment in carrying value. Depreciation, depletion and amortization are provided under the units of production method on a field basis.

Proved properties, including developed and undeveloped, and costs associated with unproven reserves, are assessed for impairment using estimated future cash flows on a field basis. Estimating future cash flows involves the use of complex judgments such as estimation of the proved and unproven oil and gas reserve quantities, risk associated with the different categories of oil and gas reserves, timing of development and production, expected future commodity prices, capital expenditures and production costs.

We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in segment profit.


	*Goodwill*

Goodwill represents the excess of cost over fair value of assets of businesses acquired. Goodwill is evaluated for impairment by first comparing our management’s estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess. We have goodwill of approximately $1 billion at December 31, 2004 and 2003 at our Exploration & Production segment.

When a reporting unit is sold or classified as held for sale, any goodwill of that reporting unit is included in its carrying value for purposes of determining any impairment or gain/loss on sale. If a portion of a reporting

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

unit with goodwill is sold or classified as held for sale and that asset group represents a business, a portion of the reporting unit’s goodwill is allocated to and included in the carrying value of that asset group. With the exception of Bio-energy, which was sold in 2002, none of the operations sold during 2004, 2003, or 2002 or classified as held for sale at December 31, 2004, represented reporting units with goodwill or businesses within reporting units to which goodwill was required to be allocated.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine the estimate of the reporting unit’s fair value. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.


	*Treasury stock*

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of shares are credited or charged to capital in excess of par value using the average-cost method.


	*Energy commodity risk management and trading activities*

Prior to 2003, we, through Power and the natural gas liquids trading operations (reported within the Midstream segment), had energy commodity risk management and trading operations that entered into energy and energy-related contracts to provide price-risk management services to our third-party customers. We held all of these contracts for trading purposes. Subsequent to 2002, our energy commodity risk management and trading operations that provided price-risk management services to third-party customers has been significantly curtailed with Power currently focused on realizing expected cash flows from its portfolio, executing new contracts to hedge its portfolio and providing functions that support our natural gas businesses. Energy contracts included futures contracts, option contracts, swap agreements, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity. Energy-related contracts included power tolling contracts, full requirements contracts, load serving contracts, storage contracts, transportation contracts, and transmission contracts. In addition, we entered into interest rate and credit default agreements to manage the interest rate and credit risk in our energy trading portfolio.

Prior to 2003, we valued all energy and energy-related contracts and physical commodity inventories used in energy commodity risk management and trading activities at fair value in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” We recognized the net change in fair value of these contracts representing unrealized gains and losses in income currently as revenues in the Consolidated Statement of Operations. Power and the natural gas liquids trading operations, reported their trading operations’ physical sales transactions net of the related purchase costs in revenues, consistent with fair value accounting for such trading activities.

In 2002, the EITF reached a consensus on Issue No. 02-3 that rescinded EITF Issue No. 98-10. As a result, beginning in 2003, we no longer apply fair value accounting to 1) energy and energy-related contracts that are not derivatives as defined in SFAS No. 133 and 2) physical commodity trading inventories. The consensus was applicable for fiscal periods beginning after December 15, 2002, and we applied the consensus effective January 1, 2003. We reported the initial application of the consensus as a cumulative effect of a change in accounting principle and the effect of initially applying the consensus reduced net income by $762.5 million, net of a $471.4 million benefit for income taxes. The charge primarily consisted of the fair value of energy-related contracts, as these contracts did not meet the definition of a derivative and thus are no longer reported at fair value. Beginning January 1, 2003, these contracts were accounted for under the accrual basis of accounting. The cumulative effect charge also included the amount by which the December 31, 2002 fair value of physical commodity trading inventories exceeded cost. We continue to carry derivatives at fair

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THE WILLIAMS COMPANIES, INC.

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value. See further discussion on our accounting and reporting for derivatives in the Derivative instruments and hedging activities section within this Note.

Prior to 2003, we determined the fair value of energy and energy-related contracts based on the nature of the transaction and the market in which the transaction was executed. We executed certain transactions in exchange-traded or over-the-counter markets for which quoted prices in active periods existed. Quoted market prices for varying periods in active markets were readily available for valuing futures contracts, swap agreements and purchase and sales transactions in the commodity markets in which Power and the natural gas liquids trading operations transacted. Market data in active periods was also available for interest rate transactions, which affected the trading portfolio. For contracts or transactions that also had terms extending into illiquid periods for which actively quoted prices were not available, Power and the natural gas liquids trading operations estimated energy commodity prices in the illiquid periods by incorporating information obtained from commodity prices in actively quoted markets, quoted prices in less active markets, prices reflected in current transactions and other market fundamental analysis. For contracts where quoted market prices were not available, primarily option contracts, transportation, storage, full requirements, load serving, transmission and power tolling contracts, Power estimated fair value using proprietary models and other valuation techniques that reflected the best information available under the circumstances. In situations where Power had received current information from negotiation activities with potential buyers of these contracts, Power considered this information in the determination of the fair value of the contract. The valuation techniques used when estimating fair value for these contracts considered option pricing theory and present value concepts incorporating risk from the uncertainty of the timing and amount of estimated cash flows. Also considered were factors such as contractual terms, quoted energy commodity market prices, estimates of energy commodity market prices in the absence of quoted market prices, volatility factors underlying the positions, estimated correlation of energy commodity prices, contractual volumes, estimated volumes under option and other arrangements, liquidity of the market in which the contract was transacted, and a risk-free market discount rate.

In estimating fair value, Power assumed liquidation of the positions in an orderly manner over a reasonable period of time in a transaction between a willing buyer and seller. Fair value reflected a risk premium that market participants would consider in their determination of fair value. Regardless of the method for which fair value was determined, we considered the risk of non-performance and credit considerations of the counterparty in estimating the fair value of all contracts. We adjusted the estimates of fair value as assumptions changed or as transactions became closer to settlement and enhanced estimates became available.

The fair value of our trading portfolio was continually subject to change due to changing market conditions and changing trading portfolio positions. Determining fair value for these contracts also involved complex assumptions including estimating natural gas and power market prices in illiquid periods and markets, estimating market volatility and liquidity and correlation of natural gas and power prices, evaluating risk arising from uncertainty inherent in estimating cash flows, and estimates regarding counterparty performance and credit considerations. Changes in valuation methodologies or the underlying assumptions could have resulted in significantly different fair values.


	*Derivative instruments and hedging activities*

We report all derivatives at fair value on the Consolidated Balance Sheet in current and noncurrent derivative assets and current and noncurrent derivative liabilities. We determine the classification of current and noncurrent based on the timing of expected future cash flows.

We utilize derivatives to manage our commodity price risk. Derivative instruments held by us to manage commodity price risk consist primarily of futures contracts, swap agreements, option contracts and forward contracts involving short- and long-term purchases and sales of a physical energy commodity. We execute

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most of these transactions in exchange-traded or over-the-counter markets for which quoted prices in active periods exist. For contracts with terms that exceed the time period for which actively quoted prices are available, we must estimate commodity prices during the illiquid periods when determining fair value. We estimate commodity prices during illiquid periods utilizing internally developed valuations incorporating information obtained from commodity prices in actively quoted markets, quoted prices in less active markets, prices reflected in current transactions and other market fundamental analysis.

Prior to fourth-quarter 2004, interest rate risk related to Power’s commodity trading and non-trading portfolio was managed on an enterprise basis by the corporate parent, where Power primarily entered into derivative instruments (usually swaps) with the corporate parent. The corporate parent determined the notional amount, term and nature of derivative instruments entered into with external parties. The effect of Power’s intercompany interest rate swaps with the corporate parent is included in Power’s segment revenues and segment profit (loss) as shown in the reconciliation within the segment disclosures (see Note 18). Interest rate derivative instruments related to these activities with external counterparties were recorded at fair value, with changes in fair value reported currently in earnings as interest rate swap loss in the Consolidated Statement of Operations below operating income (loss). During the fourth quarter of 2004, all external and intercompany interest rate derivative instruments related to managing Power’s interest rate risk were terminated.

For commodity derivatives held that are not designated in a hedging relationship, both trading and non-trading, we report changes in fair value currently in earnings. The accounting for changes in the fair value of commodity derivatives designated in a hedging relationship depends on the type of hedging relationship. In the second quarter of 2003, we elected the normal purchases and normal sales exception, available under SFAS No. 133, for certain commodity derivative contracts held by Power involving short- and long-term purchases and sales of a physical energy commodity. We reflect these contracts in current and noncurrent derivative assets and liabilities at their fair value on the date of the election less the amount of that fair value realized during settlement periods subsequent to the election.

To qualify for designation in a hedging relationship, specific criteria have to be met and the appropriate documentation maintained. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is expected to be, and remains, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. If a derivative ceases to be or is no longer expected to be highly effective, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in earnings.

For commodity derivatives designated as a hedge of a forecasted transaction (cash flow hedges), the effective portion of the change in fair value of the derivative is reported in other comprehensive income and reclassified into earnings in the period in which the hedged item affects earnings. Amounts excluded from the effectiveness calculation and any ineffective portion of the derivative’s change in fair value are recognized currently in earnings. Gains or losses deferred in accumulated other comprehensive income associated with terminated derivatives, derivatives that cease to be highly effective hedges and cash flow hedges that have been otherwise discontinued remain in accumulated other comprehensive income until the hedged item affects earnings or it is probable that the hedged item will not occur by the end of the originally specified time period or within two months thereafter. Forecasted transactions designated as the hedged item in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. When it is probable the forecasted transaction will not occur, any gain or loss deferred in accumulated other comprehensive income is recognized in earnings at that time.

For commodity derivatives designated as a hedge of a recognized asset or liability or an unrecognized firm commitment (fair value hedges), we recognize the changes in the fair value of the derivative as well as changes in the fair value of the hedged item attributable to the hedged risk each period in earnings. If we

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

terminate a firm commitment designated as the hedged item in a fair value hedge or it otherwise no longer qualifies as the hedged item, we recognize any asset or liability previously recorded as part of the hedged item currently in earnings.

In Issue No. 02-3, the EITF reached a consensus that gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. On July 31, 2003, the EITF reached a consensus on Issue No. 03-11 “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, and Not “Held for Trading Purposes” as Defined in Issue No. 02-3. In this issue, the EITF concluded that determining whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported in the income statement on a gross or net basis is a matter of judgment that depended on the relevant facts and circumstances. We report unrealized gains and losses on all commodity derivative contracts not designated as cash flow hedges on a net basis as revenues in the Consolidated Statement of Operations. We report realized gains and losses on all commodity derivative contracts that settle financially on a net basis as revenues. For commodity derivatives designated in a hedging relationship, amounts excluded from the effectiveness calculation and amounts from ineffectiveness are recorded net in revenues. For contracts that result in physical delivery, we apply the indicators provided in Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” to determine the proper reporting. Based on our assessment under Issue No. 99-19, we report revenues and purchase costs for all contracts, derivatives and non-derivatives, that result in physical delivery on a gross basis as revenues and costs and operating expenses, respectively, in the Consolidated Statement of Operations. In determining that gross reporting is appropriate, we considered several factors, including that we act as a principal in these transactions, we take title to the commodity products that we buy and sell, and we have the risks and rewards of ownership, including credit risk and latitude in establishing sales prices. EITF 02-3 and Issue No. 03-11 did not require restatement of prior year amounts. Therefore, we did not restate our Consolidated Statement of Operations for 2002 related to Power and natural gas liquids trading operations.


	*Assessment of energy-related contracts for lease classification*

The accounting for energy-related contracts requires us to assess whether certain of these contracts are executory service arrangements or leases pursuant to SFAS No. 13, “Accounting for Leases.” EITF 01-8, became effective on July 1, 2003, and provides guidance for determining whether certain contracts such as transportation, transmission, storage, full requirements, and tolling agreements are executory service arrangements or leases pursuant to SFAS No. 13. The consensus is applied prospectively to arrangements consummated or modified after July 1, 2003. Prior to July 1, 2003, we accounted for these energy-related contracts as executory service arrangements and continue this accounting, unless a contract is modified subsequent to July 1, 2003 and is evaluated to be a lease. For these executory service arrangements, the monthly demand payments are expensed as incurred. Certain of Power’s tolling agreements could be considered leases under the consensus if the tolling agreements are modified after July 1, 2003. One tolling agreement was modified subsequent to July 1, 2003 and is accounted for as an operating lease. For tolling agreements that are modified and deemed to be operating leases, the monthly demand payments are expensed as incurred. If the monthly demand payments are not incurred on a straight line basis, expense is nevertheless recognized on a straight line basis. If such tolling agreements were modified and deemed to be capital leases, the net present value of the demand payments would be reported on the balance sheet consistent with debt as an obligation under capital lease, and as an asset in property, plant and equipment.


	*Gas pipeline revenues*

Revenues for sales of products are recognized in the period of delivery, and revenues from the transportation of gas are recognized in the period the service is provided. Gas Pipeline is subject to Federal Energy Regulatory Commission (FERC) regulations and, accordingly, certain revenues collected may be

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subject to possible refunds upon final orders in pending rate cases. Gas Pipeline records estimates of rate refund liabilities considering Gas Pipeline and other third-party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks.


	*Revenues, other than gas pipeline and energy commodity risk management and trading activities*

Revenues generally are recorded when services are performed or products have been delivered.

Additionally, revenues from the domestic production of natural gas in properties for which Exploration & Production has an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on Exploration & Production’s net working interest, which are determined to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are not significant.


	*Impairment of long-lived assets and investments*

We evaluate the long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

For assets identified to be disposed of in the future and considered held for sale in accordance with SFAS No. 144, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is redetermined when related events or circumstances change.

We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other than temporary, the excess of the carrying value over the fair value is recognized in the financial statements as an impairment.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. Additionally, our management’s judgment is used to determine the probability of sale with respect to assets considered for disposal. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.


	*Capitalization of interest*

We capitalize interest on major projects during construction. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by unregulated companies are based on

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the average interest rate on debt. Interest capitalized on internally generated funds, as permitted by FERC rules, is included in non-operating other income (expense) — net.


	*Employee stock-based awards*

Employee stock-based awards are accounted for under Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Fixed-plan common stock options generally do not result in compensation expense because the exercise price of the stock options equals the market price of the underlying stock on the date of grant. The plans are described more fully in Note 13. The following table illustrates the effect on net income (loss) and income (loss) per share if we had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation.”


		Years Ended December 31,

		2004			2003			2002

		(Dollars in millions, except
		per share amount)
Net income (loss), as reported		$	163.7		$	(492.2	)	$	(754.7	)
Add: Stock-based employee compensation expense included in the Consolidated Statement of Operations, net of related tax effects			8.9			18.7			19.1
Deduct: Total stock based employee compensation expense determined under fair value based method for all awards, net of related tax effects			(25.1	)		(31.6	)		(34.5	)

Pro forma net income (loss)		$	147.5		$	(505.1	)	$	(770.1	)

Income (loss) per share:
	Basic — as reported	$	.31		$	(1.01	)	$	(1.63	)

	Basic — pro forma	$	.28		$	(1.03	)	$	(1.66	)

	Diluted — as reported	$	.31		$	(1.01	)	$	(1.63	)

	Diluted — pro forma	$	.28		$	(1.03	)	$	(1.66	)

Pro forma amounts for 2004 include compensation expense from awards of our company stock made in 2004, 2003, 2002 and 2001. Also included in the 2004 pro forma expense is $3.3 million of incremental expense associated with a stock option exchange program (see Note 13). Pro forma amounts for 2003 include compensation expense from awards made in 2003, 2002 and 2001. Also included in 2003 pro forma expense is $2 million of incremental expense associated with the stock option exchange program. Pro forma amounts for 2002 include compensation expense from awards made in 2002 and 2001 and from certain awards made in 1999.

Since compensation expense from stock options is recognized over the future years’ vesting period for pro forma disclosure purposes and additional awards are generally made each year, pro forma amounts may not be representative of future years’ amounts.


	*Income taxes*

We include the operations of our subsidiaries in our consolidated tax return. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities. Our management’s judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.

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	*Earnings (loss) per share*

Basic earnings (loss) per share is based on the sum of the weighted average number of common shares outstanding and issuable restricted and vested deferred shares. Diluted earnings (loss) per share includes any dilutive effect of stock options, unvested deferred shares and, for applicable periods presented, convertible preferred stock and convertible debt, unless otherwise noted.


	*Foreign currency translation*

Certain of our foreign subsidiaries and equity method investees use their local currency as their functional currency. These foreign currencies include the Canadian dollar, British pound and Euro. Assets and liabilities of certain foreign subsidiaries and equity investees are translated at the spot rate in effect at the applicable reporting date, and the combined statements of operations and our share of the results of operations of our equity affiliates are translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment is recorded as a separate component of other comprehensive income (loss).

Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates result in transactions gains and losses which are reflected in the Consolidated Statement of Operations.


	*Issuance of equity of consolidated subsidiary*

Sales of common stock by a consolidated subsidiary are accounted for as capital transactions with the adjustment to capital in excess of par value. No gain or loss is recognized on these transactions.


	*Recent accounting standards*

As disclosed in Derivative instruments and hedging activities and in accordance with the provisions of EITF Issue No. 99-19, we report all non-trading contracts, including both derivatives and non-derivatives, that result in physical delivery on a gross basis as revenues and costs and operating expenses. In Issue 04-13, the EITF is considering transactions in which an entity may sell inventory to another entity in the same line of business from which it also purchases inventory. Specifically, the EITF is considering whether there are any circumstances under which non-monetary transactions within the scope of APB Opinion No. 29 that involve inventory should be recognized at fair value. Additionally, the SEC has recently requested that companies disclose amounts related to certain types of buy/sell arrangements that are reported on a gross basis in the statement of operations in which the amount of purchases and sales exceed that which would typically relate to an entity’s primary operations. We have preliminarily evaluated our businesses to identify any such buy/sell arrangements. Power’s primary operations consist of dispatching electricity from power generation plants and marketing and supplying gas on behalf of our other consolidated subsidiaries. Power engages in economic hedging activities that often result in the purchase or sale of volumes in excess of its primary operations, primarily due to economic hedging activities in fluctuating commodity markets. Based on preliminary analysis, our businesses do not have activities that result in significant levels of arrangements in which terms for a buy and sell agreement are entered into concurrently or in contemplation of one another through a single transaction or a series of transactions with a single counterparty. However, further evaluation as to the impact

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to our Statement of Operations and disclosures will be required upon issuance of any new guidance by the EITF or the SEC.

The SEC staff, in a letter to the EITF Chairman, questioned whether leased mineral rights should be presented as intangible assets rather than property, plant and equipment. In March 2004, the EITF reached a consensus that all mineral rights should be considered tangible assets for accounting purposes. In September 2004, the FASB issued a Staff Position (FSP) that supported the consensus of the EITF. Therefore, no reclassification is required.

In May 2004, the FASB issued FSP No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” This guidance was effective for us beginning in third-quarter 2004 and supersedes FSP No. FAS 106-1. See Note 7 for additional information regarding this Issue, including the implementation effect for the year ended December 31, 2004.

EITF Issue No. 03-1, “The Meaning of Other Than Temporary Impairment and Its Application to Certain Investments,” contains recognition and measurement guidance that must be applied to investment impairment evaluations. Specifically, the Issue provides guidance to determine whether an investment is impaired and whether that impairment is other than temporary. The Issue applies to debt and equity securities, except equity securities accounted for under the equity method. The FASB is currently considering implementation guidance for the measurement and recognition provisions for this Issue and has delayed implementation. This Issue is required to be adopted on a prospective basis. We will continue to monitor this Issue to determine its potential impact to our Consolidated Balance Sheet and Consolidated Statement of Operations.

In December 2004, the FASB issued two Staff Positions (FSP) that provide accounting guidance on how companies should account for the effect of the American Jobs Creation Act of 2004 that was signed into law on October 22, 2004. In FSP FAS 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004”, the FASB concluded that the special tax deduction for domestic manufacturing, created by the new legislation, should be accounted for as a “special deduction” instead of a tax rate reduction. As such, the special tax deduction for domestic manufacturing is recognized no earlier than the year in which the deduction is taken on the tax return. FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004”, allows additional time to evaluate the effects of the new legislation on any plan for reinvestment or repatriation of foreign earnings for purposes of applying FASB Statement No. 109. We anticipate that the legislation will not impact our plan for reinvestment of foreign earnings and accordingly FSP FAS 109-2 is not currently expected to have a material impact on our consolidated financial statements. The FSPs were effective December 21, 2004.

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

The revised Statement allows either a modified prospective application or a modified retrospective application for adoption. We will use a modified prospective application for adoption and thus will apply the statement to new awards and to awards modified, repurchased, or cancelled after July 1, 2005. Also, for unvested stock awards outstanding as of July 1, 2005, compensation costs for the portion of these awards for which the requisite service has not been rendered will be recognized as the requisite service is rendered after July 1, 2005. Compensation costs for these awards will be based on fair value at the original grant date as estimated for the pro forma disclosures under SFAS No. 123, as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of SFAS No. 123.” Additionally,

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a modified retrospective application requires restating periods prior to July 1, 2005 on a basis consistent with the pro forma disclosures required by SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148. Since we plan to use a modified perspective application, we will not restate prior periods.

Certain of our stock awards currently result in compensation cost under APB No. 25 and related guidance. These stock awards are subject to vesting provisions and our policy is to adjust compensation cost for forfeitures when they occur. Upon the July 1, 2005 adoption of the statement, we must adjust net income for previously recognized compensation cost, net of income taxes, related to the estimated number of these outstanding stock awards that are expected to be forfeited. This adjustment will be recognized in net income as the cumulative effect of a change in accounting principle. We have not estimated the amount of the adjustment for expected forfeitures.

We currently present pro forma disclosure of net income (loss) and income (loss) per share as if compensation costs from all stock awards were recognized based on the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation.” We have not determined the Statement’s impact on net income beyond presentation of the pro forma disclosures. The Statement requires use of valuation techniques including option pricing models to estimate the fair value of employee stock awards. We are evaluating the appropriateness of several option pricing models including a Black-Scholes model and a lattice model (such as a binomial model). Application of these two models could result in different estimates of fair value with resulting differences in compensation costs.


Note 2.	Discontinued operations

The businesses discussed below represent components that have been sold or approved for sale by our Board of Directors as of December 31, 2004 and also meet all requirements to be treated as discontinued operations. Therefore, their results of operations (including any impairments, gains or losses), financial position and cash flows have been reflected in the consolidated financial statements and notes as discontinued operations.

During second-quarter 2003, our Board of Directors approved a plan authorizing management to negotiate and facilitate a sale of the assets of Gulf Liquids. Subsequent to Board approval and through third-quarter 2004, we reported Gulf Liquids as a discontinued operation. During fourth-quarter 2004, we reclassified Gulf Liquids to continuing operations within the Midstream segment for all periods presented as a result of applying EITF 03-13 (see Note 1).

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	*Summarized results of discontinued operations*

The following table presents the summarized results of discontinued operations for the years ended December 31, 2004, 2003 and 2002. Income (loss) from discontinued operations before income taxes for the year ended December 31, 2004 includes charges of approximately $153 million to increase our accrued liability associated with certain Quality Bank litigation matters (see Note 15). The provision for income taxes for the year ended December 31, 2004 is less than the federal statutory rate due primarily to the effect of net Canadian tax benefits realized from the sale of the Canadian straddle plants partially offset by the United States tax effect of earnings associated with these assets.


		2004			2003			2002

		(Millions)
Revenues		$	353.4		$	2,614.6		$	5,967.1

Income (loss) from discontinued operations before income taxes		$	(121.3	)	$	197.5		$	382.4
(Impairments) and gain (loss) on sales — net			200.5			277.7			(567.8	)
Benefit (provision) for income taxes			(8.7	)		(148.6	)		49.1

	Income (loss) from discontinued operations	$	70.5		$	326.6		$	(136.3	)

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	*Summarized assets and liabilities of discontinued operations*

The following table presents the summarized assets and liabilities of discontinued operations as of December 31, 2004 and 2003. The December 31, 2004 balances include certain Alaska retail operations that were not included in the March 31, 2004 sale but that remain held for sale. The December 31, 2003 balances include the assets and liabilities of the Canadian straddle plants and the Alaska refining, retail and pipeline operations. The assets and liabilities from discontinued operations are reflected on the Consolidated Balance Sheet as current beginning in the period they are both approved for sale and expected to be sold within twelve months.


		2004		2003

		(Millions)
Total current assets		$	12.3	$	173.9

Property, plant and equipment — net			1.2		551.2
Other non-current assets			.1		1.2

	Total non-current assets		1.3		552.4

	Total assets	$	13.6	$	726.3

Reflected on balance sheet as:
	Current assets	$	13.6	$	381.2
	Non-current assets		—		345.1

	Total assets	$	13.6	$	726.3

Long-term debt due within one year		$	—	$	1.1
Other current liabilities			1.1		80.0

	Total current liabilities		1.1		81.1

Long-term debt			—		.3
Other non-current liabilities			.5		12.0

	Total non-current liabilities		.5		12.3

	Total liabilities	$	1.6	$	93.4

Reflected on balance sheet as:
	Current liabilities	$	1.6	$	93.4


	*2004 completed transactions*


	Canadian straddle plants

On July 28, 2004, we completed the sale of the Canadian straddle plants for approximately $544 million in U.S. funds. During third-quarter 2004, we recognized a pre-tax gain on the sale of $189.8 million, which is included in (Impairments) and gain (loss) on sales — net in the preceding table of summarized results of discontinued operations. These assets were previously written down to estimated fair value, resulting in a $36.8 million impairment in 2002 and an additional $41.7 million impairment in 2003. In 2004, the fair value of the assets increased substantially due primarily to renegotiation of certain customer contracts and a general improvement in the market for processing assets. These operations were part of the Midstream segment.

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	Alaska refining, retail and pipeline operations

On March 31, 2004, we completed the sale of our Alaska refinery, retail and pipeline and related assets for approximately $304 million, subject to closing adjustments for items such as the value of petroleum inventories. We received $279 million in cash at the time of sale and $25 million in cash during the second quarter of 2004. Throughout the sales negotiation process, we regularly reassessed the estimated fair value of these assets based on information obtained from the sales negotiations using a probability-weighted approach. As a result, impairment charges of $8 million and $18.4 million were recorded in 2003 and 2002, respectively. We recognized a $3.6 million pre-tax gain on the sale during first-quarter 2004. The gain and impairment charges are included in (Impairments) and gain (loss) on sales — net in the preceding table of summarized results of discontinued operations. These operations were part of the previously reported Petroleum Services segment.


	*2003 completed transactions*


	Canadian liquids operations

During third quarter of 2003, we completed the sales of certain gas processing, natural gas liquids fractionation, storage and distribution operations in western Canada and at our Redwater, Alberta plant for total proceeds of $246 million in U.S. funds. We recognized pre-tax gains totaling $92.1 million in 2003 on the sales which are included in (Impairments) and gain (loss) on sales-net in the preceding table of summarized results of discontinued operations. These operations were part of our Midstream segment.


	Soda ash operations

On September 9, 2003, we completed the sale of our soda ash mining facility located in Colorado. The December 31, 2002 carrying value resulted from the recognition of impairments of $133.5 million and $170 million in 2002 and 2001, respectively, and reflected the then estimated fair value less cost to sell. During 2003, ongoing sale negotiations continued to provide new information regarding estimated fair value, and, as a result, we recognized additional impairment charges of $17.4 million in 2003. We also recognized a pre-tax loss on the sale in 2003 of $4.2 million. The 2003 and 2002 impairments and the loss on the sale are included in (Impairments) and gain (loss) on sales-net in the preceding table of summarized results of discontinued operations. The soda ash operations were part of the previously reported International segment.


	Williams Energy Partners

On June 17, 2003, we completed the sale of our 100 percent general partnership interest and 54.6 percent limited partner investment in Williams Energy Partners for $512 million in cash and assumption by the purchasers of $570 million in debt. In December 2003, we received additional cash proceeds of $20 million following the occurrence of a contingent event. We recognized a total pre-tax gain of $310.8 million on the sale during 2003, including the $20 million of additional proceeds, all of which is included in (Impairments) and gain (loss) on sales-net in the preceding table of summarized results of discontinued operations. We deferred an additional $113 million associated with certain environmental indemnifications we provided the purchasers under the sales agreement. In second-quarter 2004, we settled these indemnifications with an agreement to pay $117.5 million over a four-year period (see Notes 10 and 15). Williams Energy Partners was a previously reported segment.


	Bio-energy facilities

On May 30, 2003, we completed the sale of our bio-energy operations for $59 million in cash. During 2003, we recognized a pre-tax loss on the sale of $5.4 million. We recorded impairment charges totaling $195.7 million, including $23 million related to goodwill, during 2002, to reduce the carrying cost to our

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estimate of fair value, less cost to sell, at that time. Both the loss and impairment charges are included in (Impairments) and gain (loss) on sales-net in the preceding table of summarized results of discontinued operations. These operations were part of the previously reported Petroleum Services segment.


	Natural gas properties

On May 30, 2003, we completed the sale of natural gas exploration and production properties in the Raton Basin in southern Colorado and the Hugoton Embayment in southwestern Kansas. This sale included all of our interests within these basins. We recognized a $39.7 million pre-tax gain on the sale during 2003. The gain is included in (Impairments) and gain (loss) on sales-net in the preceding table of summarized results of discontinued operations. These properties were part of the Exploration & Production segment.


	Texas Gas

On May 16, 2003, we completed the sale of Texas Gas Transmission Corporation for $795 million in cash and the assumption by the purchaser of $250 million in existing Texas Gas debt. We recorded a $109 million impairment charge in 2003 reflecting the excess of the carrying cost of the long-lived assets over our estimate of fair value based on our assessment of the expected sales price pursuant to the purchase and sale agreement. The impairment charge is included in (Impairments) and gain (loss) on sales-net in the preceding table of summarized results of discontinued operations. No significant gain or loss was recognized on the subsequent sale. Texas Gas was a segment within Gas Pipeline.


	Midsouth Refinery and related assets

On March 4, 2003, we completed the sale of our refinery and other related operations located in Memphis, Tennessee for $455 million in cash. We had previously written these assets down by $240.8 million to their estimated fair value less cost to sell at December 31, 2002. We recognized a pre-tax gain on sale of $4.7 million in the first quarter of 2003. During the second quarter of 2003, we recognized a $24.7 million pre-tax gain on the sale of an earn-out agreement we retained in the sale of the refinery. The 2002 impairment charge and subsequent gains are included in (Impairments) and gain (loss) on sales-net in the preceding table of summarized results of discontinued operations. These operations were part of the previously reported Petroleum Services segment.


	Williams travel centers

On February 27, 2003, we completed the sale of our travel centers for approximately $189 million in cash. We had previously written these assets down by $146.6 million in 2002 and $14.7 million in 2001 to their then estimated fair value less cost to sell at December 31, 2002. These impairments are included in (Impairments) and gain (loss) on sales-net in the preceding table of summarized results of discontinued operations. We did not recognize a significant gain or loss on the sale. These operations were part of the previously reported Petroleum Services segment.


	*2002 completed transactions*


	Central

On November 15, 2002, we completed the sale of our Central natural gas pipeline for $380 million in cash and the assumption by the purchaser of $175 million in debt. Impairment charges totaling $91.3 million during 2002 are reflected in (Impairments) and gain (loss) on sales-net in the preceding table of summarized results of discontinued operations. Central was a segment within Gas Pipeline.

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	Mid-America and Seminole Pipelines

On August 1, 2002, we completed the sale of our 98 percent interest in Mid-America Pipeline and 98 percent of our 80 percent ownership interest in Seminole Pipeline for $1.2 billion. The sale generated net cash proceeds of $1.15 billion. In the preceding table of summarized results of discontinued operations, (Impairments) and gain (loss) on sales-net includes a pre-tax gain of $301.7 million during 2002 and an $11.4 million reduction of the gain during 2003. These assets were part of the Midstream segment.


	Kern River

On March 27, 2002, we completed the sale of our Kern River pipeline for $450 million in cash and the assumption by the purchaser of $510 million in debt. As part of the agreement, $32.5 million of the purchase price was contingent upon Kern River receiving a certificate from the FERC to construct and operate a future expansion. We received the certificate in July 2002, and recognized the contingent payment plus interest as income from discontinued operations in 2002. Included as a component of (Impairments) and gain (loss) on sales-net in the preceding table of summarized results of discontinued operations is a pre-tax loss of $6.4 million for the year ended December 31, 2002. Kern River was a segment within Gas Pipeline.


Note 3.	Investing activities


	*Investing income (loss)*

Investing income (loss) for the years ended December 31, 2004, 2003 and 2002, is as follows:


		2004			2003			2002

		(Millions)
Equity earnings*		$	49.9		$	20.3		$	73.0
Income (loss) from investments*			(35.5	)		(25.3	)		42.1
Impairments of cost-based investments			(28.5	)		(35.0	)		(12.1	)
Loss provision for WilTel receivables			—			—			(268.7	)
Interest income and other			62.1			113.2			52.6

	Total	$	48.0		$	73.2		$	(113.1	)


*	Items also included in segment profit (see Note 18).

Equity earnings for the year ended December 31, 2002, includes a benefit of $27.4 million for a contractual construction completion fee received by one of our equity affiliates whose operations are accounted for under the equity method of accounting. This equity affiliate served as the general contractor on the Gulfstream pipeline project for Gulfstream Natural Gas System (Gulfstream), an interstate natural gas pipeline subject to FERC regulations and an equity affiliate of ours. The fee paid by Gulfstream was for the early completion during second-quarter 2002 of the construction of Gulfstream’s pipeline. It was capitalized by Gulfstream as property, plant and equipment and is included in Gulfstream’s rate base to be recovered in future revenues.

Income (loss) from investments for the year ended December 31, 2004 includes:


	•	a $10.8 million additional impairment of our investment in equity securities of Longhorn, which is included in our Other segment;

	•	$6.5 million net unreimbursed Longhorn recapitalization advisory fees, which are included in our Other segment; and

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	•	a $16.9 million impairment of our equity investment in Discovery Pipeline resulting from management’s estimate of fair value, which is included in our Midstream segment.

Income (loss) from investments for the year ended December 31, 2003 includes:


	•	a $43.1 million impairment of our investment in equity and debt securities of Longhorn which is included in our Other segment;

	•	a $14.1 million impairment of our equity interest in Aux Sable, which is included in our Power segment;

	•	a $13.5 million gain on the sale of stock in eSpeed Inc., which is included in our Power segment; and

	•	an $11.1 million gain on sale of our equity interest in West Texas LPG Pipeline, L.P., which is included in our Midstream segment.

Income (loss) from investments for the year ended December 31, 2002 includes:


	•	a $58.5 million gain on sale of our investment in AB Mazeikiu Nafta, a Lithuanian oil refinery, pipeline and terminal complex, which is included in our Other segment;

	•	a $12.3 million write-off of Gas Pipeline’s investment in a pipeline project which was cancelled in 2002;

	•	a $10.4 million net write-down pursuant to the sale of our equity interest in Alliance Pipeline, a Canadian and U.S. gas pipeline, which is included in our Gas Pipeline segment; and

	•	an $8.7 million gain on sale of our general partner equity interest in Northern Border Partners, L.P., which is included in our Gas Pipeline segment.

Impairments of cost-based investments for the year ended December 31, 2004, includes a $20.8 million impairment of our investment in an Indonesian toll road, primarily due to increased uncertainty of the Indonesian economy.

Impairments of cost-based investments for the year ended December 31, 2003, includes:


	•	a $13.5 million impairment of our investment in ReserveCo, a company holding phosphate reserves; and

	•	a $13.2 million impairment of our investment in Algar Telecom S.A.

The 2002 impairments of cost-based investments relate primarily to various international investments.

For the year ending December 31, 2004, we did not perform an impairment analysis for cost-based investments with a carrying value of $16.4 million.

The loss provision for WilTel receivables in 2002 includes pre-tax charges relating to the assessment of the recovery and settlement of certain receivables and claims from WilTel. The receivables and claims resulted from our performance on $2.15 billion of guarantees and payment obligations, amounts due from WilTel related to a deferred payment for services and a minimum lease payment receivable from WilTel related to WilTel’s headquarters building and other assets.

Interest income for the year ended December 31, 2003, includes approximately $34 million of interest income at Power as the result of certain FERC proceedings.

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THE WILLIAMS COMPANIES, INC.

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	*Investments*

Investments at December 31, 2004 and 2003, are as follows:


		2004		2003

		(Millions)
Equity method:
	Gulfstream Natural Gas System, LLC — 50%	$	726.1	$	730.8
	Discovery Pipeline — 50%		184.2		194.6
	Longhorn Partners Pipeline, L.P. — 21.3%		113.2		85.1
	ACCROVEN — 49.3%		62.0		67.1
	Alliance Aux Sable — 14.6%		45.6		42.8
	Petrolera Entre Lomas S.A. — 40.8%		44.9		41.5
	Other		70.5		71.8

			1,246.5		1,233.7
Cost method:
	Various international funds		49.9		48.9
	Algar Telecom S.A — common and preferred stock		—		15.3
	Indonesian toll road		2.1		23.7
	Other		17.7		24.8

			69.7		112.7
Advances to Longhorn Partners Pipeline, L.P.			—		117.2

		$	1,316.2	$	1,463.6

In December 2003, our Midstream subsidiary made an additional $127 million investment in Discovery Pipeline that was subsequently used by Discovery Pipeline to repay maturing debt. All owners contributed amounts equal to their ownership percentage so our 50 percent ownership in Discovery remained unchanged.

Dividends and distributions received from companies carried on the equity basis were $60 million, $21 million and $81 million in 2004, 2003 and 2002, respectively. The $27.4 million Gulfstream construction completion fee described previously is included in the 2002 distributions.

Summarized financial position and results of operations of our equity method investments are as follows:

Financial position at December 31, 2004 and 2003 is as follows:


	2004		2003

	(Millions)
Current assets	$	345.1	$	281.7
Noncurrent assets		3,660.3		3,457.2
Current liabilities		357.4		325.3
Noncurrent liabilities		432.2		472.8

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Results of operations for the years ended December 31, 2004, 2003 and 2002 are as follows:


	2004		2003		2002

	(Millions)
Gross revenue	$	1,064.7	$	753.9	$	621.7
Operating income		185.0		109.7		148.6
Net income		107.8		12.6		177.4


	*Guarantees on behalf of investees*

We have guaranteed commercial letters of credit totaling $17 million on behalf of ACCROVEN. These expire in January 2006, have no carrying value and are fully collateralized with cash.

In connection with the construction of a joint venture pipeline project, we guaranteed, through a put agreement, certain portions of the joint venture’s project financing in the event of nonpayment by the joint venture. During the fourth quarter of 2004, this project, and the associated guarantees were terminated. We had not accrued any amounts related to this guarantee.

We have provided guarantees on behalf of certain entities in which we have an equity ownership interest. These generally guarantee operating performance measures and the maximum potential future exposure cannot be determined. There are no expiration dates associated with these guarantees. No amounts have been accrued at December 31, 2004.

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THE WILLIAMS COMPANIES, INC.

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Note 4.	Asset sales, impairments and other accruals

Significant gains or losses from asset sales, impairments and other accruals included in Other (income) expense — net within segment costs and expenses for the years ended December 31, 2004, 2003 and 2002, are as follows:


			(Income) Expense

			2004			2003			2002

			(Millions)
Power
	Gain on sale of Jackson power contract		$	—		$	(188.0	)	$	—
	Commodity Futures Trading Commission settlement (see Note 15)			—			20.0			—
	California rate refund and other accrual adjustments			—			19.5			—
	Impairment of goodwill			—			45.0			61.1
	Impairment of generation facilities			—			44.1			44.7
	Loss accruals and impairment of other power related assets			—			—			82.6
	Guarantee loss accruals and write-offs			—			—			56.2
Gas Pipeline
	Write-off of previously-capitalized costs on an idled segment of a pipeline			9.0			—			—
	Write-off of software development costs due to cancelled implementation			—			25.6			—
Exploration & Production
	Loss provision related to an ownership dispute			15.4			—			—
	Net gain on sales of certain natural gas properties			—			(96.7	)		(141.7	)
Midstream Gas & Liquids
	Impairment of Gulf Liquids assets			2.5			108.7			—
	Arbitration award on a Gulf Liquids insurance claim dispute			(93.6	)		—			—
	Gain on sale of the wholesale propane business			—			(16.2	)		—
	Impairment of Canadian olefin assets			—			—			78.2
Other
		Gain on sale of blending assets		—			(9.2	)		—
		Environmental accrual related to the Augusta refinery facility		11.8			—			—


	*Power*

In June 2002, we announced our intent to exit the Power business. As a result, Power pursued efforts to sell all or portions of our power, natural gas, and crude and refined products portfolios in the latter half of 2002 and in 2003. Based on bids received in these sales efforts, we impaired certain assets and projects in 2002. During 2003, we continued our focus on exiting the Power business and, as a result, impaired certain assets. In September 2004, our Board of Directors approved the decision to retain Power and end our efforts to exit that business (see Note 1).

California Rate Refund and Other Accrual Adjustments. In addition to the $19.5 million charge included in other (income) expense — net within segment costs and expenses for 2003, a $13.8 million charge is recorded within costs and operating expenses. These two amounts, totaling $33.3 million, are for California

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THE WILLIAMS COMPANIES, INC.

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rate refund liability and other accrual adjustments and relate to power marketing activities in California during 2000 and 2001. See Note 15 for further discussion.

Goodwill. The fair value of the Power reporting unit used to calculate the goodwill impairment loss in 2002 was based on the estimated fair value of the trading portfolio inclusive of the fair value of contracts with affiliates. In 2002, the trading portfolio was reflected at fair value in the financial statements and the affiliate contracts were not. The fair value of the affiliate contracts was estimated using a discounted cash flow model with natural gas pricing assumptions based on current market information.

During 2003, we were pursuing a strategy of exiting the Power business. Because of this strategy and the market conditions in which this business operated, we evaluated Power’s remaining goodwill for impairment. In estimating the fair value of the Power segment, we considered our derivative portfolio which is carried at fair value on the balance sheet and our non-derivative portfolio which is no longer carried at fair value on the balance sheet. Because of the significant negative fair value of certain of our non-derivative contracts, we may be unable to realize our carrying value of this segment. As a result, we recognized a $45 million impairment of the remaining goodwill within Power during 2003.

Generation Facilities. The 2003 impairment relates to the Hazelton generation facility. Fair value was estimated using future cash flows based on current market information and discounted at a risk adjusted rate. The 2002 impairment was related to the Worthington generation facility. Fair value was estimated based on expected proceeds from the sale of the facility, which closed in first-quarter 2003.

Loss Accruals and Impairment of Other Power Related Assets. The 2002 loss accruals and impairments of other power related assets were recorded pursuant to reducing activities associated with the distributive power generation business.

Guarantee Loss Accruals and Write-Offs. The 2002 guarantee loss accruals and write-offs within Power of $56.2 million includes accruals for commitments for certain assets that were previously planned to be used in power projects, write-offs associated with a terminated power plant project and a $13.2 million reversal of loss accruals related to the wind-down of our mezzanine lending business.


	*Midstream Gas & Liquids*

Impairment of Gulf Liquids Assets. During second-quarter 2003, our Board of Directors approved a plan authorizing management to negotiate and facilitate a sale of the assets of Gulf Liquids. We are currently negotiating purchase and sale agreements related to the sale of these assets. We expect the sale of these operations to close by the end of the second quarter of 2005. We recognized impairment charges of $2.5 million in the fourth quarter of 2004 and $108.7 million during 2003 to reduce the carrying cost of the long-lived assets to estimated fair value less costs to sell the assets. We estimated fair value based on a probability-weighted analysis of various scenarios including expected sales prices, discounted cash flows and salvage valuations. Prior to fourth-quarter 2004, the operations of Gulf Liquids were included in discontinued operations (see Note 12).

Arbitration award on a Gulf Liquids Insurance Claim Dispute. Winterthur International Insurance Company (Winterthur) issued policies to Gulf Liquids providing financial assurance related to construction contracts. After disputes arose regarding obligations under the construction contracts, Winterthur disputed coverage resulting in arbitration between Winerthur and Gulf Liquids. In July 2004, the arbitration panel awarded Gulf Liquids $93.6 million, plus interest of $9.6 million. Following the arbitration decision, Winterthur filed a Petition to Vacate the Final Award in the New York State court and Gulf Liquids filed a Cross-Petition to Confirm the Final Award. Prior to the State court’s ruling, Winterthur agreed to the terms of the award and on November 1, 2004, remitted the proceeds to us. As a result, we recognized total income of approximately $103 million related to the arbitration award in fourth-quarter 2004.

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THE WILLIAMS COMPANIES, INC.

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Canadian Olefin Assets. The 2002 impairment is associated with an olefin fractionation facility and reflects a reduction of carrying cost to management’s estimate of fair market value, determined primarily from information available from efforts to sell these assets.


	*Other*

Environmental accrual related to the Augusta refinery facility. As a result of new information obtained in the fourth quarter related to the Augusta refinery site, we have accrued additional amounts for completion of work under a current Administrative Order on Consent and reasonably estimated remediation costs. Accruals may be adjusted as more information from the site investigation becomes available (see Note 15).


Note 5.	Provision (benefit) for income taxes

The provision (benefit) for income taxes from continuing operations includes:


			2004			2003			2002

			(Millions)
Current:
	Federal		$	11.0		$	(8.8	)	$	(126.7	)
	State			(13.7	)		(17.6	)		27.5
	Foreign			11.0			8.8			21.4

				8.3			(17.6	)		(77.8	)
Deferred:
	Federal			75.1			(17.0	)		(161.9	)
	State			38.7			44.4			(58.4	)
	Foreign			9.2			(15.1	)		7.8

				123.0			12.3			(212.5	)

		Total provision (benefit)	$	131.3		$	(5.3	)	$	(290.3	)

Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the provision (benefit) for income taxes are as follows:


		2004		2003			2002

		(Millions)
Provision (benefit) at statutory rate		$	78.6	$	(22.0	)	$	(318.1	)
Increases (reductions) in taxes resulting from:
	State income taxes (net of federal benefit)		27.9		.5			(20.1	)
	Foreign operations — net		6.1		3.5			81.6
	Capital losses		—		(39.6	)		(121.2	)
	Valuation allowance/expiration charitable contributions		13.8		—			—
	Non-deductible impairment of goodwill		—		15.8			21.7
	Income tax credits recapture		—		—			26.8
	Other — net		4.9		36.5			39.0

Provision (benefit) for income taxes		$	131.3	$	(5.3	)	$	(290.3	)

During 2004, the utilization of foreign tax credits reduced the provision for income taxes by $12 million. Utilization of foreign operating loss carryovers reduced the provision for income taxes during 2003 by $19 million. The impact of foreign operations on the effective tax rate increased during 2002 due to the

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

recognition of U.S. tax on foreign dividend distributions and recording of a financial impairment on certain foreign assets for which a valuation allowance was established.

Income (loss) from continuing operations before income taxes includes $51 million of international income in 2004, $9 million of international income in 2003 and $38 million of international loss in 2002.

Significant components of deferred tax liabilities and assets as of December 31, 2004 and 2003, are as follows:


			2004		2003

			(Millions)
Deferred tax liabilities:
	Property, plant and equipment		$	2,356.5	$	2,118.8
	Derivatives — net			99.3		149.9
	Investments			442.4		514.8
	Other			201.8		195.8

		Total deferred tax liabilities		3,100.0		2,979.3

Deferred tax assets:
	Minimum tax credits			151.0		151.5
	Accrued liabilities			171.5		208.7
	Receivables			44.2		52.5
	Federal carryovers			315.3		115.7
	Foreign carryovers			54.1		46.2
	Other			44.3		125.7

		Total deferred tax assets		780.4		700.3

	Valuation allowance			61.5		67.8

		Net deferred tax assets		718.9		632.5

	Overall net deferred tax liabilities		$	2,381.1	$	2,346.8

Valuation allowances at December 31, 2004 serve to reduce the recognized tax benefit associated with charitable contribution carryovers and foreign carryovers to an amount that will, more likely than not, be realized. Valuation allowances at December 31, 2003 serve to reduce the recognized tax benefit associated with foreign asset impairments and foreign carryovers to an amount that will, more likely than not, be realized.

Undistributed earnings of certain consolidated foreign subsidiaries at December 31, 2004, amounted to approximately $88 million. No provision for deferred U.S. income taxes has been made for these subsidiaries because we intend to permanently reinvest such earnings in those foreign operations.

Cash payments for income taxes (net of refunds) were $8 million and $36 million in 2004 and 2002, respectively. Cash refunds for income taxes (net of payments) were $88 million in 2003.

At December 31, 2004, federal net operating loss carryovers are $824 million, capital loss carryovers are $13 million and charitable contribution carryovers are $64 million. We do not expect to utilize $21 million of charitable contribution carryovers prior to expiration in 2005. We expect to utilize the net operating loss carryovers prior to expiration in 2022 through 2024, capital loss carryovers prior to expiration in 2007 and the remaining $43 million charitable contribution carryovers prior to expiration in 2006 and 2007. We also do not expect to be able to utilize $54 million of foreign deferred tax assets related to carryovers.

121

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

During the course of audits of our business by domestic and foreign tax authorities, we frequently face challenges regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various tax filing positions, we record a liability for probable tax contingencies. In association with this liability, we record an estimate of related interest as a component of our current tax provision. The impact of this accrual is included within Other — net in our reconciliation of the tax provision to the federal statutory rate.


Note 6.	Earnings (loss) per share

Basic and diluted earnings (loss) per common share for the years ended December 31, 2004, 2003 and 2002, are as follows:


		2004		2003			2002

		(Dollars in millions, except per-share
		amounts; shares in thousands)
Income (loss) from continuing operations		$	93.2	$	(57.5	)	$	(618.4	)
Convertible preferred stock dividends (see Note 12)			—		29.5			90.1

Income (loss) from continuing operations available to common stockholders for basic and diluted earnings per share		$	93.2	$	(87.0	)	$	(708.5	)

Basic weighted-average shares(1)			529,188		518,137			516,793
Effect of dilutive securities:
	Unvested deferred shares		2,631		—			—
	Stock options		3,792		—			—

Diluted weighted-average shares(1)			535,611		518,137			516,793

Earnings (loss) per share from continuing operations:
	Basic	$	.18	$	(.17	)	$	(1.37	)

	Diluted	$	.18	$	(.17	)	$	(1.37	)


(1)	In October 2004, we issued approximately 33.1 million shares of common stock in association with an exchange offer on our FELINE PACS units (see Note 11).

During fourth-quarter 2004 we reclassified the results of Gulf Liquids from discontinued operations to continuing operations (see Notes 1 and 2). As a result, both the basic and diluted loss per common share from continuing operations increased by $.17 and $.04 for the years ended December 31, 2003 and 2002, respectively.

Approximately 27.5 million and 16.5 million weighted-average shares related to the assumed conversion of convertible debentures, as well as the related interest, have been excluded from the computation of diluted earnings per common share for the years ended December 31, 2004 and 2003, respectively. Inclusion of these shares would have an antidilutive effect on diluted earnings per common share. If no other components used to calculate diluted earnings per common share change, we estimate the assumed conversion of convertible debentures would become dilutive and therefore be included in diluted earnings per common share at an Income from continuing operations applicable to common stock amount of $198.1 million and $192.1 million for the years ended December 31, 2004 and 2003, respectively.

For the year ended December 31, 2003, approximately 3.6 million weighted-average stock options, approximately 6.4 million weighted-average shares related to the assumed conversion of 9.875 percent

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

cumulative convertible preferred stock and approximately 2.5 million weighted-average unvested deferred shares have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive. The unvested deferred shares will vest over the period from January 2005 to January 2008. The preferred stock was redeemed in June 2003.

For the year ended December 31, 2002, approximately 666,000 weighted-average stock options, approximately 11.3 million weighted-average shares related to the assumed conversion of the 9.875 percent cumulative convertible preferred stock and approximately 3.6 million weighted-average unvested deferred shares have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive.

The table below includes information related to options that were outstanding at the end of each respective year but have been excluded from the computation of diluted earnings per common share due to the option exercise price exceeding the fourth-quarter weighted-average market price of our common shares.


	2004		2003		2002

Options excluded (millions)		8.5		15.0		38.7
Weighted-average exercise prices of options excluded		$28.21		$22.77		$19.90
Exercise price ranges of options excluded		$14.61 - $42.29		$10.39 - $42.52		$2.27 - $42.52
Fourth-quarter weighted-average market price		$14.41		$9.76		$2.21

On February 16, 2005, we issued 10.9 million shares of common stock to the holders of an equity forward contract (FELINE PACS) in exchange for $25 cash per share (see Note 12). These shares will be a component of basic earnings per share in future periods.


Note 7.	Employee benefit plans

We provide pension benefits to substantially all eligible employees through our noncontributory defined benefit pension plans. Currently, eligible employees earn benefits primarily based on a cash balance formula. Various other formulas, as defined in the plan documents, are utilized to calculate the retirement benefits for plan participants not covered by the cash balance formula. At the time of retirement, participants may receive annuity payments, a lump sum payment or a combination of lump sum and annuity payments. In addition to our pension plans, we provide subsidized medical and life insurance benefits (other postretirement benefits) to certain eligible participants. Generally, employees hired after December 31, 1991, are not eligible for these benefits, except for participants that were employees of Transco Energy Company on December 31, 1995, and other defined participant groups. Certain of these other postretirement benefit plans, particularly the subsidized medical benefit plans, provide for retiree contributions and contain other cost-sharing features such as deductibles, copayments, and coinsurance. The accounting for these plans anticipates future cost-sharing that is consistent with our expressed intent to increase the retiree contribution level generally in line with health care cost increases.

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits for the years indicated. It also presents a reconciliation of the funded status of these benefit plans to the amounts recorded in the Consolidated Balance Sheet at December 31 of each year indicated. The annual measurement date for our plans is December 31. Changes in the obligations or assets of continuing plans associated with the transfer of such obligations or assets in a sale or planned sale reflected as discontinued operations have been reflected as divestitures in the following tables.


								Other Postretirement
		Pension Benefits						Benefits

		2004			2003			2004			2003

		(Millions)
Change in benefit obligation:
	Benefit obligation at beginning of year	$	775.9		$	788.9		$	362.4		$	410.5
	Service cost		24.0			25.5			3.2			6.2
	Interest cost		50.5			52.7			18.8			24.1
	Plan participants’ contributions		—			—			4.3			3.3
	Curtailment		(2.3	)		—			—			—
	Settlement benefits paid		(.4	)		(6.1	)		—			—
	Benefits paid		(78.8	)		(87.1	)		(24.8	)		(24.6	)
	Plan amendments		7.8			—			(75.5	)		—
	Divestiture		—			(.8	)		—			(118.3	)
	Actuarial (gain) loss		116.3			2.8			(20.0	)		61.2

	Benefit obligation at end of year		893.0			775.9			268.4			362.4

Change in plan assets:
	Fair value of plan assets at beginning of year		706.3			592.9			152.7			193.9
	Actual return on plan assets		69.6			155.8			13.2			36.1
	Divestiture		—			—			—			(70.2	)
	Employer contributions		138.8			50.8			13.5			14.2
	Plan participants’ contributions		—			—			4.3			3.3
	Benefits paid		(78.8	)		(87.1	)		(24.8	)		(24.6	)
	Settlement benefits paid		(.4	)		(6.1	)		—			—

	Fair value of plan assets at end of year		835.5			706.3			158.9			152.7

Funded status			(57.5	)		(69.6	)		(109.5	)		(209.7	)
Unrecognized net actuarial loss			295.3			195.5			23.7			44.5
Unrecognized prior service cost (credit)			4.7			(4.6	)		(53.8	)		1.5
Unrecognized transition obligation			—			—			—			23.6

Prepaid (accrued) benefit cost		$	242.5		$	121.3		$	(139.6	)	$	(140.1	)

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Amounts recognized in the Consolidated Balance Sheet consist of:


							Other Postretirement
	Pension Benefits						Benefits

	2004			2003			2004			2003

	(Millions)
Prepaid benefit cost	$	251.0		$	164.4		$	—		$	—
Accrued benefit cost		(17.6	)		(53.7	)		(139.6	)		(140.1	)
Regulatory asset		1.7			—			—			—
Accumulated other comprehensive income (before tax)		7.4			10.6			—			—

Prepaid (accrued) benefit cost	$	242.5		$	121.3		$	(139.6	)	$	(140.1	)

The regulatory asset shown in the table above is the portion of the additional minimum pension liability recognized by our FERC regulated gas pipelines. As required by FERC accounting guidelines, our FERC regulated gas pipelines are required to record the effect of an additional minimum pension liability to a regulatory asset instead of accumulated other comprehensive income.

The 2004 actuarial loss of $116.3 million for our pension plans included in the table of changes in benefit obligation reflects the impact of changes in various actuarial assumptions used to calculate the benefit obligation including the expected type of benefit payment and discount rate.

The accumulated benefit obligation for our pension plans was $823.4 million and $720.2 million at December 31, 2004 and 2003, respectively.

The projected benefit obligation and fair value of plan assets for our pension plans with projected benefit obligation in excess of plan assets were $381.2 million and $305.3 million, respectively, at December 31, 2004, and $335.0 million and $225.5 million, respectively, at December 31, 2003. The accumulated benefit obligation for pension plans with accumulated benefit obligations in excess of plan assets was $17.6 million at December 31, 2004. There were no assets for these plans at December 31, 2004. The accumulated benefit obligation and fair value of plan assets for our pension plans with accumulated benefit obligations in excess of plan assets were $279.2 million and $225.5 million, respectively, at December 31, 2003.

Net periodic pension and other postretirement benefit expense for the years ended December 31, 2004, 2003 and 2002, consists of the following:


		Pension Benefits

		2004			2003			2002

		(Millions)
Components of net periodic pension expense:
	Service cost	$	24.0		$	25.5		$	32.5
	Interest cost		50.5			52.7			59.3
	Expected return on plan assets		(64.9	)		(54.2	)		(65.3	)
	Amortization of prior service credit		(1.5	)		(2.5	)		(1.6	)
	Recognized net actuarial loss		9.4			13.7			4.0
	Regulatory asset amortization (deferral)		2.0			3.9			(1.2	)
	Settlement/curtailment expense		.1			.6			4.8
	Special termination benefit cost		—			—			29.5

Net periodic pension expense		$	19.6		$	39.7		$	62.0

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		Other Postretirement Benefits

		2004			2003			2002

		(Millions)
Components of net periodic postretirement benefit expense (income):
	Service cost	$	3.2		$	6.2		$	7.1
	Interest cost		18.8			24.1			31.8
	Expected return on plan assets		(12.4	)		(13.0	)		(18.9	)
	Amortization of transition obligation		2.7			2.7			4.1
	Amortization of prior service cost		.6			.6			.2
	Regulatory asset amortization		6.7			8.6			3.7
	Settlement/curtailment expense (income)		—			(41.9	)		13.5
	Special termination benefit cost		—			—			1.5

Net periodic postretirement benefit expense (income)		$	19.6		$	(12.7	)	$	43.0

The $41.9 million settlement/curtailment income in 2003 and $13.5 million settlement/curtailment expense in 2002 included in net periodic postretirement benefit expense (income) is included in Income (loss) from discontinued operations in the Consolidated Statement of Operations due to the settlement/curtailment directly resulting from the sale of the operations included within discontinued operations.

The weighted-average assumptions utilized to determine benefit obligations as of December 31, 2004 and 2003 are as follows:


							Other
							Postretirement
	Pension Benefits						Benefits

	2004			2003			2004			2003

Discount rate		5.86	%		6.25	%		5.75	%		6.25	%
Rate of compensation increase		5			5			N/A			N/A

The weighted-average assumptions utilized to determine net pension and other postretirement benefit expense for the years ended December 31, 2004, 2003 and 2002, are as follows:


										Other
										Postretirement
	Pension Benefits									Benefits

	2004			2003			2002			2004			2003			2002

Discount rate		6.25	%		7	%		7.5	%		6.25	%		7	%		7	%
Expected long-term rate of return on plan assets		8.5			8.5			8.5			8.5			7			7
Rate of compensation increase		5			5			5			N/A			N/A			N/A

The discount rates for our pension and other postretirement benefit plans were determined separately based on an approach specific to our plans and their respective expected benefit cash flows. With the assistance of our third-party actuary, the plans were analyzed and discount rates based on a yield curve comprised of high quality corporate bonds published by a large securities firm were matched to a highly correlated published index of high quality corporate bonds. Based on an analysis performed between each of the plans’ yield curve discount rates and the index, a formula was developed to determine the December 31, 2004, discount rates based upon the year-end published index.

The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the investment strategy included in the plans’ Investment Policy

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Statement, and the capital market projections provided by our independent investment consultant for the asset classifications in which the portfolio is invested and the target weightings of each asset classification.

The mortality assumptions used to determine the obligations for our pension and other postretirement benefit plans are related to the experience of the plans and to our third-party actuary’s best estimate of expected plan mortality. The selected mortality tables are among the most recent tables available.

The annual assumed rate of increase in the health care cost trend rate for 2005 is 9 percent, and systematically decreases to 5 percent by 2013.

The health care cost trend rate assumption has a significant effect on the amounts reported. A one-percentage-point change in assumed health care cost trend rates would have the following effects:


	Point increase		Point decrease

	(Millions)
Effect on total of service and interest cost components	$	3.7	$	(2.9	)
Effect on postretirement benefit obligation		52.0		(41.4	)

In December 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Our health care plans for retirees include prescription drug coverage. In accordance with FSP No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” the provisions of the Act were not reflected in any measures of benefit obligations or other postretirement benefit expense in the financial statements or accompanying notes until further guidance was effective. In May 2004, the FASB issued FSP No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” Although final guidance has not been issued, we believe the prescription drug benefits included in our health care plans for retirees, prior to the amendment of the plans discussed below, were actuarially equivalent to Medicare Part D. In accordance with FSP No. FAS 106-2, we reflected the effect of the subsidy on the measurement of net periodic postretirement benefit expense (income) in 2004. Net periodic postretirement benefit expense (income) for the year ended December 31, 2004, reflects a reduction of $3.4 million, including a decrease in service cost of $.4 million and decrease in interest cost of $2.7 million. The reduction in the benefit obligation was approximately $43 million as of January 1, 2004, and is included as a component of the actuarial (gain) loss in the table of changes in benefit obligation. We amended our plans in the fourth quarter of 2004 to coordinate and pay secondary to any part of Medicare, including prescription drug benefits covered by Medicare Part D. This amendment further decreased the benefit obligation by $75.5 million and is reflected as a plan amendment in the table of changes in benefit obligation as we believe our plans are no longer actuarially equivalent to Medicare Part D. The net reduction to the obligation as a result of this amendment will be amortized as a reduction to net periodic postretirement benefit expense (income) over the average remaining years of service to full eligibility for benefits.

The amount of postretirement benefit costs deferred as a net regulatory asset at December 31, 2004 and 2003, is $18 million and $24 million, respectively, and is expected to be recovered through rates over approximately 7 years.

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Our pension plans’ weighted-average asset allocations at December 31, 2004 and 2003, by asset category are as follows:


	Plan Assets at
	December 31,

	2004			2003

Equity securities		82	%		82	%
Debt securities		14			13
Other		4			5

		100	%		100	%

Included in equity securities are investments in commingled funds that invest entirely in equity securities and comprise 37 percent and 38 percent of the pension plans’ weighted-average assets at December 31, 2004 and 2003, respectively. Other assets, in the previous table, are comprised primarily of cash and cash equivalents.

Our investment strategy for the assets within the pension plans is to maximize investment returns with prudent levels of risk to meet current and projected financial requirements of the pension plans. These risks are evaluated, in part, from an asset-only standpoint as to investment allocation, investment style and manager selection. Additional risk perspectives are reviewed considering the allocation of assets and the structure of the plan liabilities and the combined effects on the plans. Our investment policy for the pension plan assets includes a target asset allocation. The target for equity securities is 84 percent and debt securities and other is 16 percent at December 31, 2004.

Our other postretirement benefit plans’ weighted-average asset allocations at December 31, 2004 and 2003, by asset category are as follows:


	Plan Assets at
	December 31,

	2004			2003

Equity securities		77	%		74	%
Debt securities		14			14
Other		9			12

		100	%		100	%

Included in equity securities are investments in commingled funds that invest entirely in equity securities and comprise 24 percent and 22 percent of the other postretirement benefit plans’ weighted-average assets at December 31, 2004 and 2003, respectively. Other assets, in the previous table, are comprised primarily of cash and cash equivalents, and insurance contract assets.

Our investment strategy for the assets within the other postretirement benefit plans is to maximize investment returns with prudent levels of risk in a tax efficient manner to meet current and projected financial requirements of the other postretirement benefit plans. These risks are evaluated, in part, from an asset-only standpoint as to investment allocation, investment style and manager selection. Additional risk perspectives are reviewed considering the allocation of assets and the structure of the plan liabilities and the combined effects on the plans. Our investment policy for the other postretirement benefit plan assets includes a target asset allocation. The target for equity securities is 80 percent and debt securities and other is 20 percent at December 31, 2004.

The following are the expected benefits to be paid in the next ten years. These estimates are based on the same assumptions previously discussed and reflect future service as appropriate. The actuarial assumptions are

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based on long-term expectations and include, but are not limited to, assumptions as to average expected retirement age and form of benefit payment. Actual benefit payments could differ significantly from expected benefit payments if near-term participant behaviors differ significantly from the actuarial assumptions.


			Other
	Pension		Postretirement
	Benefits		Benefits

	(Millions)
2005	$	39.2	$	19.3
2006		39.1		20.6
2007		39.0		21.8
2008		38.8		22.6
2009		39.4		23.2
2010-2014		235.5		119.5

We expect to contribute approximately $42 million to our pension plans and approximately $15 million to our other postretirement benefit plans in 2005.

We also maintain defined contribution plans. Costs related to continuing operations of $17 million, $18 million, and $38 million were recognized for these plans in 2004, 2003 and 2002, respectively. In 2002, these costs included the cost related to additional contributions to an employee stock ownership plan resulting from the retirement of related external debt.


Note 8.	Inventories

Inventories at December 31, 2004 and 2003, are as follows:


		2004		2003

		(Millions)
Finished goods:
	Refined products	$	.8	$	8.0
	Natural gas liquids		63.2		40.4

			64.0		48.4

Natural gas in underground storage			133.1		132.5
Materials, supplies and other			64.0		62.0

		$	261.1	$	242.9

At December 31, 2004 and 2003, less than one percent of inventories were stated at fair value. Inventories determined using the LIFO cost method were approximately six percent and ten percent of inventories at December 31, 2004 and 2003, respectively. The remaining inventories were primarily determined using the average-cost method.

If inventories valued on the LIFO cost method at December 31, 2004 and 2003, were valued at current replacement cost, the amounts would increase by $25 million and $26 million, respectively.

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Note 9.	Property, plant and equipment

Property, plant and equipment at December 31, 2004 and 2003, is as follows:


		2004			2003

		(Millions)
Cost:
	Power	$	188.2		$	190.7
	Gas Pipeline		8,140.3			7,949.1
	Exploration & Production(1)		3,690.6			3,235.7
	Midstream Gas & Liquids(1)		4,189.9			4,126.7
	Other		243.8			250.2

			16,452.8			15,752.4
Accumulated depreciation, depletion and amortization			(4,566.0	)		(4,018.4	)

		$	11,886.8		$	11,734.0


(1)	Certain assets above are currently pledged as collateral to secure debt (see Note 11).

Depreciation, depletion and amortization expense for property, plant and equipment was $667.4 million in 2004, $655.6 million in 2003 and $644.8 million in 2002.

Property, plant and equipment includes approximately $218 million at December 31, 2004 and $676 million at December 31, 2003 of construction in progress which is not yet subject to depreciation. In addition, property of Exploration & Production includes approximately $561 million at December 31, 2004 and $675 million at December 31, 2003 of capitalized costs related to properties with unproven reserves not yet subject to depletion. Additionally, property of Exploration & Production includes approximately $1.5 billion (net of approximately $276 million of accumulated amortization) of developed and undeveloped leaseholds.

Commitments for construction and acquisition of property, plant and equipment are approximately $26 million at December 31, 2004.

Net property, plant and equipment includes approximately $1.2 billion at December 31, 2004 and 2003, related to amounts in excess of the original cost of the regulated facilities within Gas Pipeline as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.

We adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” on January 1, 2003. As a result, we recorded a liability of $33.4 million representing the present value of expected future asset retirement obligations at January 1, 2003, and an increase to earnings of $1.2 million reflected as a cumulative effect of a change in accounting principle. The asset retirement obligation at December 31, 2004 and December 31, 2003 is $55 million and $39 million, respectively. The increase in the obligation in 2004 is primarily due to new assets placed in service and revised estimated retirement dates.

The obligations relate to producing wells, offshore platforms, underground storage caverns and gas gathering well connections. At the end of the useful life of each respective asset, we are legally obligated to plug both producing wells and storage caverns and remove any related surface equipment, to dismantle offshore platforms, and to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment. We have not recorded liabilities for pipeline transmission assets, processing assets, and gas gathering systems pipelines. A reasonable estimate of the fair value of the retirement obligations for these

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assets cannot be made as the remaining life of these assets is not currently determinable. If the Statement had been in effect at the beginning of 2002, the impact to our 2002 income from continuing operations and net income would have been immaterial. There would have been no impact on earnings per share.


Note 10.	Accounts payable and accrued liabilities

Under our cash-management system, certain subsidiaries’ cash accounts reflect credit balances to the extent checks written have not been presented for payment. Accounts payable includes approximately $6 million of these credit balances at December 31, 2004 and $27 million at December 31, 2003.

On May 26, 2004, we were released from certain historical indemnities, primarily related to environmental remediation, for an agreement to pay $117.5 million (see Note 15). We had previously deferred $113 million of a gain on sale related to these indemnities. At the date of sale, the deferred revenue and identified obligations related to the indemnities totaled $102 million. At December 31, 2004, the carrying value of this settlement is $74.8 million. We will pay the balance in three installments of $27.5 million, $20 million, and $35 million on July 1, 2005, 2006 and 2007, respectively.

We have provided guarantees in the event of nonpayment by our previously owned communications subsidiary, WilTel, on certain lease performance obligations that extend through 2042 and have a maximum potential exposure of approximately $49 million at December 31, 2004. Our exposure declines systematically throughout the remaining term of WilTel’s obligations.

Accrued liabilities at December 31, 2004 and 2003, are as follows:


	2004		2003

	(Millions)
Interest	$	238.2	$	269.7
Employee costs		151.3		153.6
Taxes other than income taxes		109.1		101.2
Net lease obligation		35.6		59.7
Guarantees and payment obligations related to WilTel		44.4		46.1
Deposits received from customers relating to energy risk management and trading and hedging activities		17.7		25.8
Income taxes		4.0		6.2
Structured indemnity settlement		26.7		—
Other		364.7		325.6

	$	991.7	$	987.9

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Note 11.	Debt, leases and banking arrangements

Notes payable and long-term debt

Notes payable and long-term debt at December 31, 2004 and 2003, are as follows:


			Weighted-
			Average			December 31,
			Interest
			Rate(1)			2004			2003

			(Millions)
Secured notes payable				—		$	—		$	3.3

Long-term debt:
	Secured long-term debt(2)
		Notes, 6.62%-9.45%, payable through 2016		8.0	%	$	219.7		$	243.7
		Notes, adjustable rate, payable through 2016		4.6	%		587.3			602.5
	Unsecured long-term debt
		Debentures, 5.5%-10.25%, payable through 2033		7.1	%		1,408.4			1,645.2
		Notes, 5.935%-9.25%, payable through 2032		7.7	%		5,671.3			9,404.3
		Note, adjustable rate, due 2008		3.8	%		75.0			—
		Other, payable through 2007		6.0	%		.3			79.3

Total long-term debt, including current portion							7,962.0			11,975.0
	Long-term debt due within one year						(250.1	)		(935.2	)

Long-term debt						$	7,711.9		$	11,039.8


(1)	At December 31, 2004

(2)	Includes $492.5 million and $497.5 million of long-term debt secured by substantially all of the assets of Williams Production RMT Company at December 31, 2004 and 2003. The value of these assets significantly exceeds the outstanding debt. The remaining $314.5 million and $348.7 million at December 31, 2004 and 2003, respectively, of long-term debt is collateralized by certain fixed assets of our Venezuelan subsidiary with a net book value of $444.6 million and $466.3 million at December 31, 2004 and 2003, respectively.

Long-term debt for 2004 and 2003 includes $73.1 million and $1.1 billion, respectively, of FELINE PACS, payable in 2007 associated with our FELINE PACS offering.


	Recent significant events

On February 25, our Exploration & Production segment amended its $500 million secured variable rate note. The amendment reduced the floating interest rate from the London InterBank Offered Rate (LIBOR) plus 3.75 percent to LIBOR plus 2.5 percent. The amendment also extended the maturity date from May 30, 2007 to May 30, 2008. The amendment provides for an additional reduction in the interest rate by 25 basis points, or 0.25 percent, if we meet certain credit-rating requirements. The significant covenants were not altered by the amendment.

On March 15, we retired $679 million of senior, unsecured 9.25 percent notes. The amount represented the outstanding balance remaining after the fourth-quarter 2003 tender that retired $721 million of the original $1.4 billion balance.

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In June, we retired approximately $1.34 billion aggregate principal amount of a specified series of our outstanding notes and debentures. In May, we also repurchased approximately $255 million of various notes with maturity dates ranging from 2006 to 2011. In conjunction with these tendered notes and debentures and related consents, and early retirements, we paid premiums of approximately $79 million. The premiums, as well as related fees and expenses together totaling approximately $97 million, are recorded as early debt retirement costs.

On July 20, WilPro Energy Services (PIGAP II) Limited, one of our subsidiaries, received a notice of default from the Venezuelan state oil company, Petroleos de Venezuela S.A. (PDVSA), relating to certain operational issues alleging that our subsidiary is not in compliance under a services agreement with PDVSA. We do not believe there is a basis for such notice. The notice of default from PDVSA could have resulted in an event of default with respect to project loans totaling approximately $208 million. On January 10, 2005, we obtained a waiver from the lenders concerning the notice of default from PDVSA. The waiver will immediately terminate if PDVSA takes any action evidencing their intention to pursue any right or remedy for the alleged event of default. To date, PDVSA has not taken any action, nor given us any indication that they will take any action, to pursue any such right or remedy relating to this matter. Moreover, in February of 2005, PDVSA provided us with a letter confirming that there is no current event of default under the services agreement. Since there is no current event of default, we will continue to classify this debt as non-current on our balance sheet.

In September, we retired approximately $793 million of our 8.625 percent senior notes due 2010. In conjunction with these tendered notes and related consents, we paid premiums of approximately $134.5 million. The premiums, as well as related fees and expenses, together totaling approximately $154.7 million, are recorded as early debt retirement costs.

On October 18, we completed an offer to exchange up to 43.9 million of our FELINE PACS in the form of Income PACS for one share of our common stock plus $1.47 in cash for each unit. The exchange resulted in approximately 33.1 million of the 44 million issued and outstanding units being tendered and accepted for exchange. The exchange offer reduced our 6.5 percent notes, due 2007, by approximately $827 million and increased our common stock outstanding by 33.1 million shares. The effect of the exchange, including a pre-tax charge for related expenses of approximately $25 million, was recorded as early debt retirement costs in the fourth quarter. Following the exchange and in connection with the remarketing of the remaining senior notes, we retired approximately $200 million additional notes on November 16. A pre-tax charge for remarketing expenses of approximately $5 million was recorded in the fourth quarter. At December 31, 2004, approximately $73 million of the original $1.1 billion note obligation and 10.9 million equity forward contracts remain outstanding. The remaining equity forward contracts were exercised on February 16, 2005, and the remaining notes are due on February 16, 2007. As a result of the November 16, remarketing, the interest rate on the remaining obligation was reset to 5.935 percent. See Note 12 for additional information.


	Revolving credit and letter of credit facilities

In April 2004, we entered into two unsecured bank revolving credit facilities totaling $500 million. These facilities provide for both borrowings and issuing letters of credit, but are used primarily for issuing letters of credit. At December 31, 2004, letters of credit totaling $472 million have been issued by the participating financial institution under these facilities and no revolving credit loans were outstanding. We are required to pay to the bank fixed fees at a weighted-average rate of 3.64 percent on the total committed amount of the facilities. In addition, we pay interest on any borrowings at a fluctuating rate comprised of either a base rate or LIBOR. We were able to obtain the unsecured credit facilities because the funding bank syndicated its associated credit risk into the institutional investor market, which allows for the resale of certain restricted securities to qualified institutional buyers. Upon the occurrence of certain credit events, letters of credit outstanding under the agreement become cash collateralized creating a borrowing under the facilities.

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Concurrently the bank can deliver the facilities to the institutional investors, whereby the investors replace the bank as lender under the facilities. Upon such occurrence, we will pay:


	•	a fixed facility fee at a weighted average rate of 3.19 percent to the investors,

	•	interest on borrowings under the $400 million facility equal to a fixed rate of 3.57 percent, and

	•	interest on borrowings under the $100 million facility at a fluctuating LIBOR interest rate.

To facilitate the syndication of these facilities, the bank established trusts funded by the institutional investors. The assets of the trusts serve as collateral to reimburse the bank for our borrowings in the event the facilities are delivered to the investors. Thus, we have no asset securitization or collateral requirements under the new facilities. During second-quarter 2004, use of these new facilities replaced existing facilities and released a total of approximately $500 million of restricted cash, restricted investments and margin deposits which secured our previous $800 million revolving and letter of credit facility.

In January 2005, these facilities were terminated and replaced with two new facilities via an exchange offer and consent solicitation carried out by the bank. The two new facilities contain the same terms outlined above, but almost all of the restrictive covenants and events of default in the previous credit agreements were removed or made less restrictive. As a result, as of January 20, 2005, the restrictive covenants no longer limit the following:


	•	certain payments, including investments and the payment of quarterly dividends to no greater than $.05 per common share;

	•	asset sales;

	•	the use of proceeds from permitted asset sales;

	•	transactions with affiliates; and

	•	the incurrence of additional indebtedness and issuance of disqualified stock.

On May 3, 2004, we entered into a new three-year, $1 billion secured revolving credit facility which is available for borrowings and letters of credit. The previous $800 million revolver and letter of credit facility was terminated. In August 2004, we expanded the credit facility by an additional $275 million. At December 31, 2004, letters of credit totaling $422 million have been issued by the participating institutions under this facility and no revolving credit loans were outstanding. Northwest Pipeline and Transco have access to $400 million each under the facility. The new facility is secured by certain Midstream assets, including substantially all of our southwest Wyoming, Wamsutter, San Juan Conventional, Manzanares and Torre Alta systems. Additionally, the facility is guaranteed by WGP. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the facilitating bank’s base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus an applicable margin. We are also required to pay a commitment fee (currently .375 percent annually) based on the unused portion of the facility. The applicable margins and commitment fee are based on the relevant borrower’s senior unsecured long-term debt ratings. Significant financial covenants under the credit agreement include the following.


	•	Ratio of debt to capitalization no greater than (i) 75 percent for the period June 30, 2004 through December 31, 2004, (ii) 70 percent for the period after December 31, 2004 through December 31, 2005, and (iii) 65 percent for the remaining term of the agreement. At December 31, 2004, we are in compliance with this covenant as our ratio of debt to capitalization is approximately 61 percent.

	•	Ratio of debt to capitalization no greater than 55 percent for Northwest Pipeline and Transco.

	•	Ratio of EBITDA to Interest, on a rolling four quarter basis (or, in the first year, building up to a rolling four quarter basis), no less than (i) 1.5 for the periods ending September 30, 2004 through

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		March 31, 2005, (ii) 2.0 for any period after March 31, 2005 through December 31, 2005, and (iii) 2.5 for the remaining term of the agreement. Through December 31, 2004, we are in compliance with this covenant as we exceed the compliance level by approximately 90 percent.


	Issuances and Retirements

A summary of significant issuances and payments of long-term debt for the year ended December 31, 2004, including the retirements discussed above, is as follows:


				Principal
Issue/Terms		Due Date		Amount

				(Millions)
Issuances of long-term debt in 2004:
	Floating rate senior unsecured notes		2008	$	75.0
Retirements/prepayments of long-term debt in 2004:
	6.5% senior notes (FELINE PACS exchange offer)		2007		827.2
	8.625% senior notes		2010		792.8
	9.25% senior unsecured notes		2004		678.5
	6.75% Putable Asset Term Securities		2006		370.3
	6.5% unsecured notes		2006		251.4
	6.25% unsecured debentures		2006		231.0
	6.5% unsecured notes		2008		221.9
	5.935% senior notes (FELINE PACS remarketing)		2007		199.7
	7.55% unsecured notes		2007		118.8
	6.625% unsecured notes		2004		127.5
	7.25% unsecured notes		2009		85.0
	Long-term debt collateralized by certain receivables		N/A		78.7
	7.125% unsecured notes		2011		60.0
	Various notes, 2.86%-9.45%, including adjustable rate		2007-2016		46.7

Aggregate minimum maturities of long-term debt for each of the next five years are as follows:


	(Millions)

2005	$	246.8
2006		119.0
2007		396.3
2008		715.6
2009		53.1

Cash payments for interest (net of amounts capitalized) were as follows: 2004 — $849 million; 2003 — $1.3 billion; and 2002 — $856 million.


	*Restricted net assets*

Terms of certain of our subsidiaries’ borrowing arrangements with lenders limit the transfer of funds to the corporate parent. At December 31, 2004, approximately $165 million of net assets of consolidated subsidiaries was restricted. Of this amount, $91 million is reported as restricted cash on our Consolidated Balance Sheet. In addition, certain equity method investees’ borrowing arrangements and foreign government

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regulations limit the amount of dividends or distributions to the corporate parent. Restricted net assets of equity method investees was approximately $17.4 million at December 31, 2004.


	*Leases-lessee*

Future minimum annual rentals under noncancelable operating leases as of December 31, 2004, are payable as follows:


	(Millions)

2005	$	194.5
2006		191.1
2007		187.6
2008		185.1
2009		181.5
Thereafter		1,411.7

Total	$	2,351.5

The above amounts include obligations of approximately $2.17 billion related to a tolling agreement at Power that is now accounted for as an operating lease as a result of changes to the contract terms subsequent to our implementation of EITF 01-8 (see Note 1). Under the tolling agreement, Power has the exclusive right to capacity and fuel conversion services as well as ancillary services associated with electric generation facilities that are currently in operation in southern California. Current annual rentals under this tolling agreement are approximately $162 million with approximately 13 years remaining on the agreement as of December 31, 2004. These rentals are substantially offset through year 2010 with income from sales and other transactions made possible by the tolling agreement.

Total rent expense was $206 million in 2004, $110 million in 2003 and $93 million in 2002. Included in 2004 rent expense was $136 million at Power related primarily to a tolling agreement, including $9 million of contingent rentals which are primarily based on utilization of the leased property or changes in the capacity of the power generating facility. Income from sales and other transactions made possible by the tolling agreement was approximately $129 million in 2004, and includes $6 million of contingent rental income.


Note 12.	Stockholders’ equity

Concurrent with the sale of Kern River to MidAmerican Energy Holdings Company (MEHC) on March 27, 2002, we issued approximately 1.5 million shares of 9.875 percent cumulative convertible preferred stock to MEHC for $275 million. The terms of the preferred stock allowed the holder to convert, at any time, one share of preferred stock into 10 shares of our common stock at $18.75 per share. The preferred shares carried no voting rights and had a liquidation preference equal to the stated value of $187.50 per share plus any dividends accumulated and unpaid. Dividends on the preferred stock were payable quarterly. At the time the preferred stock was issued, the conversion price was less than the market price of our common stock and thus deemed beneficial to the purchaser. The benefit was recorded as a noncash dividend of $69.4 million, which was a reduction to our retained earnings with an offsetting amount recorded as an increase to capital in excess of par value.

On June 10, 2003, we redeemed all of the outstanding 9.875 percent cumulative-convertible preferred shares for approximately $289 million, plus $5.3 million for accrued dividends. The $13.8 million of payments in excess of carrying value of the shares was also recorded as a dividend. These shares were repurchased with proceeds from a private placement of $300 million of 5.5 percent junior subordinated convertible debentures

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due 2033. These notes, which are callable after seven years, are convertible at the option of the holder into our common stock at a conversion price of approximately $10.89 per share.

In January 2002, we issued $1.1 billion of 6.5 percent notes payable in 2007 that were subject to remarketing in 2004. Each note was bundled with an equity forward contract (together, the FELINE PACS units) and sold in a public offering for $25 per unit. The equity forward contract required the holder of each note to purchase one share of our common stock for $25 three years from issuance of the contract. On September 17, 2004, we initiated an offer to exchange up to 43.9 million FELINE PACS units for one share of our common stock plus $1.47 in cash for each unit. The offer resulted in approximately 33.1 million of the 44 million issued and outstanding units being tendered and accepted for exchange. The exchange offer reduced our 6.5 percent notes, due 2007, by approximately $827 million and increased our common stock outstanding by 33.1 million shares. On February, 16, 2005, the settlement date, the holders of the remaining 10.9 million equity forward contracts purchased one share of our common stock for $25.

We maintain a Stockholder Rights Plan, as amended and restated on September 21, 2004, under which each outstanding share of our common stock has a right (as defined in the plan) attached. Under certain conditions, each right may be exercised to purchase, at an exercise price of $50 (subject to adjustment), one two-hundredth of a share of Series A Junior Participating Preferred Stock. The rights may be exercised only if an Acquiring Person acquires (or obtains the right to acquire) 15 percent or more of our common stock or commences an offer for 15 percent or more of our common stock. The rights, which until exercised do not have voting rights, expire in 2014 and may be redeemed at a price of $.01 per right prior to their expiration, or within a specified period of time after the occurrence of certain events. In the event a person becomes the owner of more than 15 percent of our common stock, each holder of a right (except an Acquiring Person) shall have the right to receive, upon exercise, our common stock having a value equal to two times the exercise price of the right. In the event we are engaged in a merger, business combination or 50 percent or more of our assets, cash flow or earnings power is sold or transferred, each holder of a right (except an Acquiring Person) shall have the right to receive, upon exercise, common stock of the acquiring company having a value equal to two times the exercise price of the right.


Note 13.	Stock-based compensation


	*Plan information*

The Williams Companies, Inc. 2002 Incentive Plan (the “Plan”) was approved by stockholders on May 16, 2002, and amended and restated on May 15, 2003 and January 23, 2004. The Plan provides for common-stock-based awards to both employees and non-management directors. Upon approval by the stockholders, all prior stock plans were terminated resulting in no further grants being made from those plans. However, awards outstanding in those prior plans remain in those plans with their respective terms and provisions.

The Plan permits the granting of various types of awards including, but not limited to, stock options, restricted stock and deferred stock. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved. At December 31, 2004, 49.7 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 25.2 million shares were available for future grants. At December 31, 2003, 56.2 million shares of our common stock were reserved for issuance, of which 28.3 million were available.


	*Loans*

Several of our prior stock plans allowed us to loan money to participants to exercise stock options using stock certificates as collateral. Effective November 14, 2001, we no longer issue loans under the stock option loan programs. Loan holders were offered a one-time opportunity in January 2002 to refinance outstanding

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loans at a market rate of interest commensurate with the borrower’s credit standing. The refinancing was in the form of a full recourse note, with interest payable annually in cash and a loan maturity date of December 31, 2005. We continue to hold the collateral shares for certain borrowers and may review any borrower’s financial position at any time. The variable rate of interest on the loans was determined at the signing of the promissory note to be 1.75 percent plus the current three-month London Interbank Offered Rate (LIBOR). The rate is subject to change every three months beginning with the first three-month anniversary of the note. The amount of loans outstanding at December 31, 2004 and 2003, totaled approximately $22 million (net of a $7 million allowance) and $28 million (net of a $5 million allowance), respectively.


	*Deferred shares*

Deferred shares are valued at the date of award. Deferred share expense is recognized in the performance year or over the vesting period, depending on the terms of the awards. Expense related to forfeited shares is recognized in the year of the forfeiture.


		2004		2003		2002

		(Millions, except per-share amounts)
Deferred shares granted			1.8		.2		2.7
Deferred shares issued			.9		1.3		.5
Weighted average fair value of
	deferred shares granted, per share	$	10.54	$	4.68	$	12.26
Deferred share expense		$	14	$	30	$	31


	*Options*

The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after grant.

On May 15, 2003, our shareholders approved a stock option exchange program. Under this 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 to be determined at the grant date of the new options. Surrendered options were cancelled June 26, 2003, and replacement options were granted on December 29, 2003. We did not recognize any expense pursuant to the stock option exchange. However, for purposes of pro forma disclosures, we recognized additional expense related to these new options. The remaining pro forma expense on the cancelled options was amortized through year-end 2004.

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The following summary reflects stock option activity for our common stock and related information for 2004, 2003 and 2002:


	2004					2003					2002

				Weighted-					Weighted-					Weighted-
				Average					Average					Average
				Exercise					Exercise					Exercise
	Options			Options		Options			Price		Options			Price

	(Millions)					(Millions)					(Millions)
Outstanding — beginning of year		25.7		$	14.63		38.8		$	19.85		25.6		$	28.23
Granted		4.5			9.96		4.1	*		9.76		15.8			6.64
Exercised		(5.5	)		3.93		(.2	)		5.86		(.5	)		11.77
Canceled		(2.7	)		22.35		(17.0	)**		25.60		(2.1	)		26.31

Outstanding — end of year		22.0		$	15.36		25.7		$	14.63		38.8		$	19.85

Exercisable — end of year		17.1		$	16.87		12.3		$	24.23		21.7		$	27.42


*	Includes 3.9 million shares that were granted December 29, 2003, under the stock option exchange program, described above.


**	Includes 10.4 million shares that were cancelled on June 26, 2003 under the stock option exchange program, described above.

The following summary provides information about options for our common stock that are outstanding and exercisable at December 31, 2004:


								Stock Options
		Stock Options Outstanding						Exercisable

						Weighted-
				Weighted-		Average				Weighted-
				Average		Remaining				Average
				Exercise		Contractual				Exercise
Range of Exercise Prices		Options		Price		Life		Options		Price

		(Millions)						(Millions)
$2.27 to $5.40			5.2	$	2.95		7.7 years		5.1	$	2.91
$6.96 to $9.93			4.4		9.90		8.7 years		.2		9.35
$10.00 to $12.22			3.9		10.18		4.5 years		3.5		10.19
$12.59 to $31.56			4.6		20.07		2.9 years		4.4		20.29
$33.51 to $42.29			3.9		37.75		3.1 years		3.9		37.75

	Total		22.0	$	15.36		5.5 years		17.1	$	16.87

The estimated fair value at date of grant of options for our common stock granted in 2004, 2003 and 2002, using the Black-Scholes option pricing model, is as follows:


		2004			2003*			2002

Weighted-average grant date fair value of options for our common stock granted during the year		$	4.54		$	2.95		$	2.77

Assumptions:
	Dividend yield		0.4	%		1	%		1	%
	Volatility		50	%		50	%		56	%
	Risk-free interest rate		3.3	%		3.1	%		3.6	%
	Expected life (years)		5.0			5.0			5.0

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The 2003 weighted average fair value and assumptions do not reflect options that were granted December 29, 2003, as part of the stock option exchange program which is described above. The fair value of these options is $1.58, which is the difference in the fair value of the new options granted and the fair value of the exchanged options. The assumptions used in the fair value calculation of the new options granted were: 1) dividend yield of .40 percent; 2) volatility of 50 percent; 3) weighted average expected remaining life of 3.4 years; and 4) weighted average risk free interest rate of 1.99 percent.

Pro forma net income (loss) and earnings per share, assuming we had applied the fair-value method of SFAS No. 123, “Accounting for Stock-Based Compensation,” in measuring compensation cost beginning with 1997 employee stock-based awards is disclosed under Employee stock-based awards in Note 1.


Note 14.	Financial instruments, derivatives, guarantees and concentration of credit risk


	*Financial instruments fair value*


	Fair-value methods

We used the following methods and assumptions in estimating our fair-value disclosures for financial instruments:

Cash and Cash Equivalents and Restricted Cash: The carrying amounts of cash equivalents reported in the balance sheet approximate fair value due to the short-term maturity of these instruments.

Notes and Other Non-current Receivables, Margin Deposits and Deposits Received from Customers Relating to Energy Trading and Hedging Activities: The carrying amounts reported in the balance sheet approximate fair value as these instruments have interest rates approximating market.

Restricted Investments: The 2003 restricted investments consisted of short-term U.S. Treasury securities. Fair value was determined using indicative year-end traded prices.

Advances to Affiliates: The 2003 carrying amounts reported in the balance sheet approximated fair value as these instruments were written down to estimated fair value based on terms of a recapitalization plan (see Note 3).

Notes Payable: The carrying amounts of notes payable approximated fair value due to the short-term maturity of these instruments.

Long-Term Debt: The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on the prices of similar securities with similar terms and credit ratings. At December 31, 2004 and 2003, 89 percent and 92 percent, respectively, of our long-term debt was publicly traded. We used the expertise of outside investment banking firms to assist with the estimate of the fair value of long-term debt.

Energy Derivatives: Energy derivatives include:


	•	futures contracts,

	•	forward purchase and sale contracts,

	•	swap agreements,

	•	option contracts, and

	•	interest-rate swap agreements and futures contracts.

Fair value of energy derivatives is determined based on the nature of the transaction and the market in which transactions are executed. Most of these transactions are executed in exchange-traded or over-the-

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counter markets for which quoted prices in active periods exist. For contracts with lives exceeding the time period for which quoted prices are available, we determined fair value by estimating commodity prices during the illiquid periods. We estimated commodity prices during illiquid periods by incorporating information obtained from commodity prices in actively quoted markets, prices reflected in current transactions and market fundamental analysis.

Foreign Currency Derivatives: Fair value was determined by discounting estimated future cash flows using forward foreign exchange rates derived from the year-end forward exchange curve.

Interest-Rate Swaps: Fair value was determined by discounting estimated future cash flows using forward-interest rates derived from the year-end yield curve.


	Carrying Amounts and Fair Values of Our Financial Instruments


		2004						2003

		Carrying			Fair			Carrying			Fair
Asset (Liability)		Amount			Value			Amount			Value

		(Millions)
Cash and cash equivalents		$	930.0		$	930.0		$	2,315.7		$	2,315.7
Restricted cash (current and noncurrent)			112.7			112.7			206.9			206.9
Notes and other noncurrent receivables			80.0			80.5			140.0			140.0
Investments:
	Cost based investments		69.7			(a	)		112.7			(a	)
	Restricted investments (current and noncurrent)		—			—			381.3			381.3
	Advances to affiliates		—			—			117.2			117.2
Notes payable			—			—			(3.3	)		(3.3	)
Long-term debt, including current portion			(7,962.0	)		(8,857.2	)		(11,975.0	)		(12,291.5	)
Structured Indemnity settlement (see Note 15)			(74.8	)		(74.8	)		—			—
Margin deposits			131.7			131.7			553.9			553.9
Deposits received from customers relating to energy risk management and trading and hedging activities			(17.7	)		(17.7	)		(25.8	)		(25.8	)
Guarantees			45.0			(b	)		46.8			(b	)
Energy derivatives:
	Energy trading and non-trading derivatives		718.7			718.7			842.6			842.6
	Energy commodity cash flow hedges		(328.8	)		(328.8	)		(295.8	)		(295.8	)
Foreign currency derivatives			—			—			(55.2	)		(55.2	)
Interest-rate swaps			—			—			(20.2	)		(20.2	)
Other derivatives			1.4			1.4			2.7			2.7


(a)		These investments are primarily in non-publicly traded companies for which it is not practicable to estimate fair value.

(b)		It is not practicable to estimate the fair value of these financial instruments because of their unusual nature and unique characteristics.

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	*Energy derivatives*


	Energy trading and non-trading derivatives not utilized in hedging activities

We have energy trading and non-trading derivatives that have not been designated as or do not qualify as SFAS No. 133 hedges. As such, the net change in their fair value is recognized in revenues in the Consolidated Statement of Operations. Our Power segment has trading derivatives that provide risk management services to our third-party customers and non-trading derivatives that hedge or could possibly hedge our long-term structured contract positions on an economic basis. Certain of our non-trading derivatives became eligible to be and were designated as SFAS No. 133 cash flow hedges after our decision to retain our power business. Many of these non-trading derivatives had an existing fair value prior to their designation as cash flow hedges. In addition, our Exploration & Production segment enters into natural gas basis swap agreements that are not designated in a hedging relationship under SFAS No. 133.

We also hold significant non-derivative energy-related contracts in our Power trading and non-trading portfolios. These have not been included in the financial instruments table above because they do not qualify as financial instruments. See Note 1 regarding Energy commodity risk management and trading activities for further discussion of the non-derivative energy-related contracts.


	Derivative contracts include the following:

Futures Contracts: Futures contracts are commitments to either purchase or sell a commodity at a future date for a specified price and are generally settled in cash, but may be settled through delivery of the underlying commodity. Exchange-traded or over-the-counter markets providing quoted prices in active periods are available. Where quoted prices are not available, other market indicators exist for the futures contracts we enter into. The fair value of these contracts is based on quoted prices.

Swap Agreements and Forward Purchase and Sale Contracts: Swap agreements require us to make payments to (or receive payments from) counterparties based upon the differential between a fixed and variable price or variable prices of energy commodities for different locations. Forward contracts, which involve physical delivery of energy commodities, contain both fixed and variable pricing terms. Swap agreements and forward contracts are valued based on prices of the underlying energy commodities over the contract life and contractual or notional volumes with the resulting expected future cash flows discounted to a present value using a risk-free market interest rate.

Options: Physical and financial option contracts give the buyer the right to exercise the option and receive the difference between a predetermined strike price and a market price at the date of exercise. These contracts are valued based on option pricing models considering prices of the underlying energy commodities over the contract life, volatility of the commodity prices, contractual volumes, estimated volumes under option and other arrangements and a risk-free market interest rate.

Interest-Rate Derivatives: Interest-rate swap and futures agreements, including those with the parent, were used to manage the interest rate risk in Power’s energy trading and non-trading portfolio. Under swap agreements, Power paid a fixed rate and received a variable rate on the notional amount of the agreements. Financial futures contracts were commitments to either purchase or sell a financial instrument, such as a Eurodollar deposit, U.S. Treasury bond or U.S. Treasury note, at a future date for a specified price. These were generally settled in cash, but could have been settled through delivery of the underlying instrument. The fair value of these contracts was determined by discounting estimated future cash flows using forward interest rates derived from interest rate yield curves. The corporate parent determined the level, term and nature of derivative instruments entered into with external parties. These external derivative instruments did not qualify for hedge accounting per SFAS 133; therefore, changes in their fair value were reflected in earnings, the effect of which is shown as interest rate swap loss in the Consolidated Statement of Operations below operating income. We terminated or liquidated all remaining interest-rate derivatives in fourth quarter 2004.

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We execute most of these transactions in exchange-traded or over-the-counter markets for which quoted prices in active periods exist. For contracts with terms that exceed the time period for which actively quoted prices are available, we must estimate commodity prices during the illiquid periods when determining fair value. We estimate commodity prices during illiquid periods utilizing internally developed valuations incorporating information obtained from commodity prices in actively quoted markets, quoted prices in less active markets, prices reflected in current transactions and other market fundamental analysis.


	Energy commodity cash flow hedges

We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage our exposure to the variability in expected future cash flows attributable to commodity price risk associated with forecasted purchases of natural gas and electricity, capacity as well as forecasted purchases and sales of electricity. These derivatives have been designated as cash flow hedges.

Our Power segment sells electricity produced by our electric generation facilities, obtained contractually through tolling agreements or obtained through marketplace transactions at different locations throughout the United States. We also buy electricity and capacity to serve our full requirements agreements in the Southeast. To reduce exposure to a decrease in revenues and increase in costs from fluctuations in electricity prices, we enter into fixed-price forward physical sales and purchase contracts to fix the price of anticipated electricity sales and electricity and capacity purchases, respectively.

Our electric generation facilities and tolling agreements require natural gas for the production of electricity. To reduce the exposure to increasing costs of natural gas due to changes in market prices, we enter into natural gas futures contracts, swap agreements and fixed-price forward physical purchases to fix the prices of anticipated purchases of natural gas.

Power’s cash flow hedges are expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item, changes in the creditworthiness of counterparties and the hedging derivative contract having a fair value upon designation.

Our Exploration & Production segment produces, buys and sells natural gas at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in natural gas market prices, we hedge price risk by entering into natural gas futures contracts and swap agreements to fix the price of anticipated sales and purchases of natural gas. We also enter into basis swap agreements as part of our overall natural gas price risk management program to reduce the locational price risk associated with our producing basins. Exploration & Production’s cash flow hedges are expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item.

Changes in the fair value of our cash flow hedges are deferred in other comprehensive income and are reclassified into revenues in the same period or periods during which the hedged forecasted purchases or sales affect earnings or when it is probable that the hedged forecasted transaction will not occur either by the end of the originally specified time period or within an additional two-month period. Approximately $13 million of net gains from hedge ineffectiveness is included in revenues in the Consolidated Statement of Operations during 2004. Hedge ineffectiveness in 2003 was immaterial. We discontinued hedge accounting in 2003 for certain contracts when it became probable that the related forecasted transactions would not occur. As a result, we reclassified net losses of $5 million out of accumulated other comprehensive income and into revenues in the Consolidated Statement of Operations in 2003. For 2004 and 2003, there were no derivative gains or losses excluded from the assessment of hedge effectiveness. As of December 31, 2004, we had hedged portions of future cash flows associated with anticipated energy commodity purchases and sales for up to

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8 years. Based on recorded values at December 31, 2004, approximately $124 million of net losses (net of income tax benefits of $77 million) will be reclassified into earnings within the next year. These recorded values are based on market prices of the commodities as of December 31, 2004. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized in 2005 will likely differ from these values. These gains or losses will offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.


	*Foreign currency derivatives*

Until July 2004, we had an intercompany Canadian-dollar-denominated note receivable that was exposed to foreign-currency risk. We entered into a forward contract to fix the U.S. dollar principal cash flows from this note. This derivative was designated as a cash flow hedge and was expected to be highly effective over the period of the hedge. Hedge accounting was discontinued effective October 1, 2002 because the hedge was no longer expected to be highly effective. All gains or losses subsequent to October 1, 2002, were recognized in other income (expense) — net below operating income. Gains and losses from the change in fair value of the derivatives prior to October 1, 2002, were deferred in other comprehensive income (loss) and reclassified to other income (expense) — net below operating income as the Canadian-dollar-denominated note receivable impacted earnings as it was translated into U.S. dollars. The $2.4 million of net losses (net of income tax benefits of $1.5 million) deferred in other comprehensive income (loss) at December 31, 2002, was reclassified into earnings during 2003. In 2002, there were no derivative gains or losses recorded in the Consolidated Statement of Operations from hedge ineffectiveness or from amounts excluded from the assessment of hedge effectiveness, and no foreign currency hedges were discontinued as a result of it becoming probable that the forecasted transaction would not occur.


	*Guarantees*

In addition to the guarantees and payment obligations discussed elsewhere in these footnotes (see Notes 3 and 10), we have issued guarantees and other similar arrangements with off-balance sheet risk as discussed below.

In connection with the 1993 public offering of units in the Williams Coal Seam Gas Royalty Trust (Royalty Trust), our Exploration & Production segment entered into a gas purchase contract for the purchase of natural gas in which the Royalty Trust holds a net profits interest. Under this agreement, we guarantee a minimum purchase price that the Royalty Trust will realize in the calculation of its net profits interest. We have an annual option to discontinue this minimum purchase price guarantee and pay solely based on an index price. The maximum potential future exposure associated with this guarantee is not determinable because it is dependent upon natural gas prices and production volumes. No amounts have been accrued for this contingent obligation as the index price continues to substantially exceed the minimum purchase price.

A foreign bank is a defendant in litigation related to a loan they provided to us. We have repaid the loan and indemnified the bank for legal fees and potential losses that may result from this litigation. We are unable to determine the maximum amount of future payments that we could be required to pay as it is dependent upon the ultimate resolution of the claim. However, we believe the probability is remote that a judgment will be made against the bank that we will have to pay. We have accrued $0.1 million at December 31, 2004, related to this guarantee.

We are required by certain foreign lenders to ensure that the interest rates received by them under various loan agreements are not reduced by taxes by providing for the reimbursement of any domestic taxes required to be paid by the foreign lender. The maximum potential amount of future payments under these indemnifications is based on the related borrowings, generally continue indefinitely unless limited by the

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underlying tax regulations, and have no carrying value. We have never been called upon to perform under these indemnifications.


	*Concentration of credit risk*


	Cash equivalents and restricted investments

Our cash equivalents consist of high-quality securities placed with various major financial institutions with credit ratings at or above BBB by Standard & Poor’s or Baa1 by Moody’s Investors Service. Restricted investments consisted of short-term U.S. Treasury Securities.


	Accounts and notes receivable

The following table summarizes concentration of receivables, net of allowances, by product or service at December 31, 2004 and 2003:


			2004		2003

			(Millions)
Receivables by product or service:
	Sale or transportation of natural gas and related products		$	859.0	$	793.9
	Power sales and related services			441.9		704.9
	Income taxes receivable			1.1		17.5
	Other			120.8		96.9

		Total	$	1,422.8	$	1,613.2

Natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the eastern and northwestern United States, Rocky Mountains, Gulf Coast, Venezuela and Canada. Power customers include the California Independent System Operator (ISO), the California Department of Water Resources, other power marketers and utilities located throughout the majority of the United States. Other receivables in 2004 includes a $54.1 million receivable from WilTel. We sold this receivable in January 2005, for $54.6 million. Other receivables for 2003 include sales or transportation of petroleum products. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

As of December 31, 2004, Power had approximately $61 million of certain power receivables net of related allowances from the ISO and the California Power Exchange (compared to $177 million at December 31, 2003). We believe that we have appropriately reflected the collection and credit risk associated with receivables and derivative assets in our Consolidated Balance Sheet and Statement of Operations at December 31, 2004.


	Derivative assets and liabilities

We have a risk of loss as a result of counterparties not performing pursuant to the terms of their contractual obligations. Risk of loss can result from credit considerations and the regulatory environment of the counterparty. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances.

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The concentration of counterparties within the energy and energy trading industry impacts our overall exposure to credit risk in that these counterparties are similarly influenced by changes in the economy and regulatory issues. Additional collateral support could include the following:


	•	letters of credit,

	•	payment under margin agreements,

	•	guarantees of payment by credit worthy parties, and

	•	transfers of ownership interests in natural gas reserves or power generation assets.

We also enter into netting agreements to mitigate counterparty performance and credit risk.

The gross credit exposure from our derivative contracts as of December 31, 2004 is summarized below.


	Investment
Counterparty Type	Grade(a)		Total

	(Millions)
Gas and electric utilities	$	556.4	$	609.4
Energy marketers and traders		1,185.7		3,268.3
Financial institutions		2,023.9		2,023.9
Integrated gas and oil		90.0		90.0
Other		5.6		21.1

	$	3,861.6		6,012.7

Credit reserves				(26.4	)

Gross credit exposure from derivatives(b)			$	5,986.3

We assess our credit exposure on a net basis. The net credit exposure from our derivatives as of December 31, 2004 is summarized below.


	Investment
Counterparty Type	Grade(a)		Total

	(Millions)
Gas and electric utilities	$	93.4	$	119.8
Energy marketers and traders		454.9		613.3
Financial institutions		217.4		217.4
Other		1.1		1.6

	$	766.8		952.1

Credit reserves				(26.4	)

Net credit exposure from derivatives(b)			$	925.7

(a)

We determine investment grade primarily using publicly available credit ratings. We included counterparties with a minimum Standard & Poor’s of BBB — or Moody’s Investors Service rating of Baa3 in investment grade. We also classify counterparties that have provided sufficient collateral, such as cash, standby letters of credit, parent company guarantees, and property interests, as investment grade.


(b)		One counterparty within the California power market represents more than ten percent of the derivative assets and is included in investment grade. Standard & Poor’s and Moody’s Investors Service do not currently rate this counterparty. We included this counterparty in the investment grade column based upon contractual credit requirements.

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	Revenues

In 2004 and 2003, there were no customers that exceeded 10 percent of our consolidated revenues. In 2002, eight of Power’s customers exceeded 10 percent of our revenues with sales from each customer of $516.9 million, $505.5 million, $482.5 million, $474.8 million, $408.7 million, $379.2 million, $377.5 million and $358.9 million, respectively. The revenues from these customers in 2002 are net of cost of sales with the same customer consistent with fair-value accounting (see Note 1). The sum of these net revenues exceeds our total revenues because there are additional customers with whom we have negative net revenues (due to the costs from these customers exceeding the revenues) which offset this sum.

Certain of our counterparties lack financial stability and creditworthiness, which may adversely impact their ability to perform under contracts. Revenues from one of Power’s counterparties, which has a credit rating below investment grade, constitutes approximately five percent of Power’s gross revenues. Our exposure to this counterparty is mitigated by the existence of a netting arrangement.


Note 15.	Contingent liabilities and commitments


	*Rate and regulatory matters and related litigation*

Our interstate pipeline subsidiaries have various regulatory proceedings pending. As a result of rulings in certain of these proceedings, a portion of the revenues of these subsidiaries has been collected subject to refund. The natural gas pipeline subsidiaries have accrued approximately $9 million for potential refund as of December 31, 2004.


	*Issues resulting from California energy crisis*

Subsidiaries of our Power segment are engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 have been challenged in various proceedings including those before the Federal Energy Regulatory Commission (FERC). These challenges include refund proceedings, California Independent System Operator (ISO) fines, summer 2002 90-day contracts, investigations of alleged market manipulation including withholding, gas indices and other gaming of the market, new long-term power sales to the State of California that were subsequently challenged and civil litigation relating to certain of these issues. We have entered into settlements with the State of California (State Settlement), major California utilities (Utilities Settlement), and others that have substantially resolved each of these issues. However, certain issues remain open at the FERC and for other non-settling parties, such as the DOJ.


	Refund proceedings

Although we have entered into the State Settlement and Utilities Settlement which resolve the refund issues among the settling parties, we have potential refund exposure to non-settling parties (e.g., various California end users that have not agreed to opt into the Utilities Settlement). As a part of the Utilities Settlement, we funded escrow accounts that we anticipate will satisfy any ultimate refund determinations in favor of the non-settling parties. We are also owed interest from counterparties in the California market during the refund period for which we have recorded a receivable of approximately $30 million at December 31, 2004. Collection of the interest is subject to the conclusion of this proceeding. A request for rehearing of the order approving the Utilities Settlement is pending at the FERC. Therefore, we continue to participate in the FERC refund case and related proceedings. Challenges to virtually every aspect of the refund proceeding, including the refund period, are now pending at the Ninth Circuit Court of Appeals.

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	Summer 2002 90-day contracts

On May 2, 2002, PacifiCorp filed a complaint with the FERC against us seeking relief from rates contained in three separate confirmation agreements between PacifiCorp and Power (known as the Summer 2002 90-Day Contracts). PacifiCorp filed similar complaints against three other suppliers. PacifiCorp alleged that the rates contained in the contracts are unjust and unreasonable. On June 26, 2003, the FERC affirmed the administrative law judge’s initial decision dismissing the complaints. PacifiCorp has appealed the FERC’s order to the United States Court of Appeals for the Ninth Circuit after the FERC denied rehearing of its order on November 10, 2003.


	Investigations of alleged market manipulation

As a result of various allegations and FERC orders, in 2002 the FERC initiated investigations of manipulation of the California gas and power markets. As they related to us, these investigations included economic and physical withholding, so-called “Enron Gaming Practices” and gas index manipulation.

Each of these FERC investigations of alleged market manipulation was resolved pursuant to the Utilities Settlement that is discussed above in Refund proceedings.

As also discussed below in Reporting of natural gas-related information to trade publications, on November 8, 2002, we received a subpoena from a federal grand jury in Northern California seeking documents related to our involvement in California markets. We have completed our response to the subpoena. This subpoena is a part of the broad United Sates Department of Justice (DOJ) investigation regarding gas and power trading.


	Long-term contracts

In February 2001, during the height of the California energy crisis, we entered into a long-term power contract with the State of California to assist in stabilizing its market. The State of California later sought to rescind this contract. Following settlement discussions between the State and us on the contract issue as well as other state initiated proceedings and allegations of market manipulation, we entered into the State Settlement that includes renegotiated long-term energy contracts. These contracts are made up of block energy sales, dispatchable products and a gas contract. The State Settlement does not extend to criminal matters or matters of willful fraud, but did resolve civil complaints brought by the California Attorney General against us and the State of California’s refund claims that are discussed above. In addition, the State Settlement resolved ongoing investigations by the States of California, Oregon and Washington. Certain private class action and other civil plaintiffs who have initiated class action litigation against us and others in California based on allegations against us with respect to the California energy crisis also executed the State Settlement. On June 29, 2004, the court approved the State Settlement, making it effective as to plaintiffs and terminating the class actions as to us. A limited group did opt out of the State Settlement. An appeal of the approval order is currently pending. Litigation by non-California plaintiffs, or relating to reporting of natural gas information to trade publications, as discussed below, will continue. As of December 31, 2004, pursuant to the terms of the State Settlement, we have transferred ownership of six LM6000 gas powered electric turbines, have made three payments totaling $87 million to the California Attorney General, and have funded a $15 million fee and expense fund associated with civil actions that are subject to the State Settlement. An additional $60 million remains to be paid to the California Attorney General (or his designee) over the next five years, with the final payment of $15 million due on January 1, 2010.


	Redondo Beach Taxes

On February 5, 2005, Power received a tax assessment letter, addressed to AES Redondo Beach, L.L.C. and Power, from the city of Redondo Beach, California, in which the city asserted that approximately

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$33 million in back taxes and approximately $39 million in interest and penalties are owed related to natural gas used at the generating facility operated by AES Redondo Beach. On the same date, Power was served with a subpoena from the city related to the tax assessment. Under Power’s tolling agreement related to the Redondo Beach generating facility, we believe that AES Redondo Beach is responsible for taxes of the nature asserted by the city.


	*Reporting of natural gas-related information to trade publications*

We disclosed on October 25, 2002, that certain of our natural gas traders had reported inaccurate information to a trade publication that published gas price indices. As noted above, on November 8, 2002, we received a subpoena from a federal grand jury in Northern California seeking documents related to our involvement in California markets, including our reporting to trade publications for both gas and power transactions. We completed our response to the subpoena. On December 17, 2004, a former trader with Power pled guilty to manipulation of gas prices through misreporting to an industry trade periodical. The DOJ’s investigation of us in this matter is continuing and it is reasonably possible that material penalties could result. However, a reasonable estimate of such amount cannot be determined at this time. In addition, the Commodity Futures Trading Commission (CFTC) has conducted an investigation of us regarding this issue. On July 29, 2003, we reached a settlement with the CFTC where in exchange for $20 million, the CFTC closed its investigation and we did not admit or deny allegations that we had engaged in false reporting or attempted manipulation. Civil suits based on allegations of manipulating the gas indices have been brought against us and others in federal court in New York, Tennessee, Washington, Oregon and California and in state court in California.


	*Investigations related to natural gas storage inventory*

We responded to a subpoena from the CFTC and inquiries from the FERC related to investigations involving natural gas storage inventory issues. Through some of our subsidiaries, we own and operate natural gas storage facilities. On August 30, 2004, the CFTC announced that it had concluded its investigation. The FERC inquiries relate to the sharing of non-public data concerning inventory levels and the potential uses of such data in natural gas trading. The FERC investigation is continuing and we are engaged in discussions with FERC staff regarding the ultimate disposition of this matter.


	*Mobile Bay expansion*

On December 3, 2002, an administrative law judge at the FERC issued an initial decision in Transco’s general rate case which, among other things, rejected the recovery of the costs of Transco’s Mobile Bay expansion project from its shippers on a “rolled-in” basis and found that incremental pricing for the Mobile Bay expansion project is just and reasonable. The administrative law judge’s initial decision is subject to review by the FERC. On March 26, 2004, the FERC issued an Order on Initial Decision in which it reversed certain parts of the administrative law judge’s holding and accepted Transco’s proposal for rolled-in rates. Power holds long-term transportation capacity on the Mobile Bay expansion project. If the FERC had adopted the decision of the administrative law judge on the pricing of the Mobile Bay expansion project and also required that the decision be implemented effective September 1, 2001, Power could have been subject to surcharges of approximately $59 million, excluding interest, through December 31, 2004, in addition to increased costs going forward. On April 26, 2004, several parties, including Transco filed requests for rehearing of the FERC’s March 26, 2004 order. These requests are still pending.


	*Enron bankruptcy*

We have outstanding claims against Enron Corp. and various of its subsidiaries (collectively “Enron”) related to Enron’s bankruptcy filed in December 2001. In March 2002, we sold $100 million of our claims

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against Enron to a third party for $24.5 million. On December 23, 2003, Enron filed objections to these claims. Under the sales agreement, the purchaser of the claims may demand repayment of the purchase price, plus interest assessed at an annual rate of 7.5 percent, for that portion of the claims still subject to objections beginning 90 days following the initial objection. To date, the purchaser has not demanded repayment.


	*Environmental matters*


	Continuing operations

Since 1989, our Transco subsidiary has had studies underway to test certain of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. Transco has responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of its sites. Transco has identified polychlorinated biphenyl (PCB) contamination in compressor systems, soils and related properties at certain compressor station sites. Transco has also been involved in negotiations with the EPA and state agencies to develop screening, sampling and cleanup programs. In addition, Transco commenced negotiations with certain environmental authorities and other programs concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. The costs of any such remediation will depend upon the scope of the remediation. At December 31, 2004, Transco had accrued liabilities of $23 million related to PCB contamination, potential mercury contamination, and other toxic and hazardous substances.

We also accrued environmental remediation costs for our natural gas gathering and processing facilities, primarily related to soil and groundwater contamination. At December 31, 2004, we had accrued liabilities totaling approximately $8 million for these costs.

Actual costs incurred for these matters will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by the EPA and other governmental authorities and other factors.

In August 2004, the New Mexico Environment Department (NMED) issued a Notice of Violation (NOV) to one of our subsidiaries, Williams Field Services Company (WFS), alleging various air permit violations primarily related to WFS’s alleged failure to control volatile organic compound emissions from three conventional dehydrators in 2001. The NOV specified that the maximum statutory penalty for such violations is approximately $13.7 million. NMED and WFS are negotiating a possible resolution to this matter and WFS anticipates that any proposed penalty will be significantly lower than the maximum statutory amount. Additionally, in August 2004, WFS discovered and self-disclosed to the NMED that WFS was out of compliance with certain requirements of the operating permit issued under Title V of the Clean Air Act Amendments of 1990 at the Kutz gas processing plant. NMED and WFS are also negotiating a possible resolution to this matter.


	Former operations, including operations classified as discontinued

In connection with the sale of certain assets and businesses, we have retained responsibility, through indemnification of the purchasers, for environmental and other liabilities existing at the time the sale was consummated, as described below.


	*Agrico*

In connection with the 1987 sale of the assets of Agrico Chemical Company, we agreed to indemnify the purchaser for environmental cleanup costs resulting from certain conditions at specified locations to the extent such costs exceed a specified amount. At December 31, 2004, we had accrued liabilities of approximately $11 million for such excess costs.

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We are also in discussions with defendants involved in two class action damages lawsuits involving this former chemical fertilizer business. Settlement among those defendants was judicially approved in October 2004. We were not a named defendant in the settled lawsuits, but have contractual obligations to participate with the named defendants in the ongoing environmental remediation. One defendant has filed a Motion to Compel us to participate in arbitration regarding the contractual obligations. A hearing was held on that Motion on September 2, 2004 and the judge ordered the Motion to Compel and subsequent issues severed from the class action. On November 3, 2004, we removed the severed case to the United States District Court in the Northern District of Florida in Pensacola. Agrico filed its motion to remand on November 22, 2004. We then filed a Motion to Dismiss on January 21, 2005. A hearing on the Motion to Remand is set for March 23, 2005.


	*Williams Energy Partners*

As part of our June 17, 2003 sale of Williams Energy Partners (see Note 2), we provided certain environmental indemnities to the purchaser. On May 26, 2004, the parties reached an agreement for buyout of certain indemnities in the form of a structured cash settlement. The agreement releases us from essentially all environmental indemnity obligations under the June 2003 sale of Williams Energy Partners and two related agreements. The agreement also transferred most third party litigation matters related to Williams Energy Partners’ assets to the purchaser.


	*Other*

At December 31, 2004, we had accrued environmental liabilities totaling approximately $30 million related primarily to our:


	•	potential indemnification obligations to purchasers of our former retail petroleum and refining operations;

	•	former propane marketing operations, bio-energy facilities, petroleum products and natural gas pipelines;

	•	discontinued petroleum refining facilities; and

	•	exploration and production and mining operations.

These costs include (1) certain conditions at specified locations related primarily to soil and groundwater contamination and (2) any penalty assessed on Williams Refining & Marketing, LLC (Williams Refining) associated with noncompliance with EPA’s benzene waste “NESHAP” regulations. In 2002, Williams Refining submitted to the EPA a self-disclosure letter indicating noncompliance with those regulations. This unintentional noncompliance had occurred due to a regulatory interpretation that resulted in under-counting the total annual benzene level at Williams Refining’s Memphis refinery. Also in 2002, the EPA conducted an all-media audit of the Memphis refinery. On August 25, 2004, Williams Refining and its new owner met with the EPA and the DOJ to discuss alleged violations and proposed penalties due to noncompliance issues identified in the multi-media report, including the benzene NESHAP issue. Discussion between the EPA, the DOJ and Williams Refining to resolve the allegations of noncompliance are ongoing. In connection with the sale of the Memphis refinery in March 2003, there are certain indemnification obligations to the purchaser.

We were a plaintiff in litigation involving the environmental investigation and subsequent cleanup of the Augusta refinery. In April 2004, we received a court order to participate in mediation before the end of June with the defendant to attempt to reach a settlement prior to going to trial. The litigation has been resolved and Williams Petroleum Services, LLC has accrued additional amounts of $11.8 million for completion of the work under the current Administrative Order on Consent and reasonably anticipated remediation costs. Accruals may be adjusted as more information from the site investigation becomes available.

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Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws.


	Summary of environmental matters

Actual costs incurred for these matters could be substantially greater than amounts accrued depending on the actual number of contaminated sites identified, the actual amount and extent of contamination discovered, the final cleanup standards mandated by the EPA and other governmental authorities and other factors.


	*Other legal matters*


	Royalty indemnifications

In connection with agreements to resolve take-or-pay and other contract claims and to amend gas purchase contracts, Transco entered into certain settlements with producers which may require the indemnification of certain claims for additional royalties which the producers may be required to pay as a result of such settlements. Transco, through its agent, Power, continues to purchase gas under contracts which extend, in some cases, through the life of the associated gas reserves. Certain of these contracts contain royalty indemnification provisions that have no carrying value. Producers have received and may receive other demands, which could result in claims pursuant to royalty indemnification provisions. Indemnification for royalties will depend on, among other things, the specific lease provisions between the producer and the lessor and the terms of the agreement between the producer and Transco. Consequently, the potential maximum future payments under such indemnification provisions cannot be determined.

As a result of these settlements, Transco has been sued by certain producers seeking indemnification from Transco. Transco is currently a defendant in one lawsuit in which a producer has asserted damages, including interest calculated through December 31, 2004, of approximately $10 million. On July 11, 2003, at the conclusion of the trial, the judge ruled in Transco’s favor and subsequently entered a formal judgment. However, the plaintiff continues to seek an appeal.


	Will Price (formerly Quinque)

On June 8, 2001, fourteen of our entities were named as defendants in a nationwide class action lawsuit which had been pending against other defendants, generally pipeline and gathering companies, for more than one year. The plaintiffs allege that the defendants, including us, have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs. After the court denied class action certification and while motions to dismiss for lack of personal jurisdiction were pending, the court granted the plaintiffs’ motion to amend their petition on July 29, 2003. The fourth amended petition, which was filed on July 29, 2003, deletes all of our defendants except two Midstream subsidiaries. All defendants intend to continue their opposition to class certification.


	Grynberg

In 1998, the DOJ informed us that Jack Grynberg, an individual, had filed claims on behalf of himself and the federal government, in the United States District Court for the District of Colorado under the False Claims Act against us and certain of our wholly owned subsidiaries. The claims sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. In connection with our sale of Kern River and Texas Gas, we agreed to indemnify the purchasers for any liability relating to this claim, including legal fees. The maximum amount of future payments that we could potentially be required to pay under these indemnifications depends upon the ultimate resolution of the claim and cannot currently be determined. Grynberg has also filed claims against approximately 300 other energy

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companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. On April 9, 1999, the DOJ announced that it was declining to intervene in any of the Grynberg qui tam cases, including the action filed in federal court in Colorado against us. On October 21, 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui tam cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. Grynberg’s measurement claims remain pending against us and the other defendants; the court previously dismissed Grynberg’s royalty valuation claims. The defendants have filed a number of joint motions to dismiss Grynberg’s claims on subject matter jurisdictional bases. Oral argument on these motions has been set for March 17, 2005, and we expect a decision in the second quarter of 2005.

On August 6, 2002, Jack J. Grynberg, and Celeste C. Grynberg, Trustee on Behalf of the Rachel Susan Grynberg Trust, and the Stephen Mark Grynberg Trust, served us and one of our Exploration & Production subsidiaries with a complaint in the state court in Denver, Colorado. The complaint alleges that the defendants have used mismeasurement techniques that distort the BTU heating content of natural gas, resulting in the alleged underpayment of royalties to Grynberg and other independent natural gas producers. The complaint also alleges that defendants inappropriately took deductions from the gross value of their natural gas and made other royalty valuation errors. Under various theories of relief, the plaintiff is seeking actual damages of between $2 million and $20 million based on interest rate variations and punitive damages in the amount of approximately $1.4 million dollars. Our motion to stay the proceedings in this case based on the pendency of the False Claims Act litigation discussed in the preceding paragraph was granted in January 2003. In September 2004, Grynberg moved to lift the stay and filed an amended complaint against one of our Exploration & Production subsidiaries. This subsidiary filed an answer in January 2005, denying liability for the damages claimed.


	Securities class actions

Numerous shareholder class action suits have been filed against us in the United States District Court for the Northern District of Oklahoma. The majority of the suits allege that we and co-defendants, WilTel Communications (WilTel), previously an owned subsidiary known as Williams Communications, and certain corporate officers, have acted jointly and separately to inflate the stock price of both companies. Other suits allege similar causes of action related to a public offering in early January 2002, known as the FELINE PACS offering. These cases were filed against us, certain corporate officers, all members of our board of directors and all of the offerings’ underwriters. These cases have all been consolidated and an order has been issued requiring separate amended consolidated complaints by our equity holders and WilTel equity holders. The underwriter defendants have requested indemnification from these cases. If granted, costs incurred as a result of these indemnifications will not be covered by our insurance policies. The amended complaint of the WilTel securities holders was filed in September 2002, and the amended complaint of our securities holders was filed in October 2002. This amendment added numerous claims related to Power. On April 2, 2004, the purported class of our securities holders filed a partial motion for summary judgment with respect to certain disclosures made in connection with our public offerings during the class period. The lead plaintiff subsequently filed to withdraw from the proceeding and a new process was held to determine the lead plaintiff. This process has concluded and the Motion for Summary Judgment is now moot. Derivative shareholder suits have been filed in state court in Oklahoma, all based on similar allegations. The state court approved motions to consolidate and to stay these Oklahoma suits pending action by the federal court in the shareholder suits. We have directors and officers insurance which we believe provides coverage for these claims, but there can be no assurance that the ultimate resolution of this litigation will not include some amount outside of insurance.

In addition, four class action complaints have been filed against us, the members of our Board of Directors and members of our benefits and investment committees under the Employee Retirement Income Security Act (ERISA) by participants in our 401(k) plan. A motion to consolidate these suits has been approved. In July 2003, the court dismissed us and our Board from the ERISA suits, but not the members of

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the benefits and investment committees to whom we might have an indemnity obligation. If it is determined that we have an indemnity obligation, we expect that any costs incurred will be covered by our insurance policies. On June 7, 2004, the Court granted plaintiffs’ request to amend their complaint to add additional investment committee members and to again name the Board of Directors. On December 21, 2004, the Court denied the Plaintiffs’ Motion for Partial Summary Judgment against the Director Defendants and denied the Motions to Dismiss filed by the Directors and certain Committee Defendants. On March 4, 2005, Plaintiffs filed a Third Amended Complaint again seeking to add us as a defendant in this matter. The U.S. Department of Labor is also independently investigating our employee benefit plans.


	Oklahoma securities investigation

On April 26, 2002, the Oklahoma Department of Securities issued an order initiating an investigation of us and WilTel regarding issues associated with the spin-off of WilTel and regarding the WilTel bankruptcy. We have no pending inquiries in this investigation, but are committed to cooperate fully in the investigation.


	Federal Income Tax Litigation

One of our wholly-owned subsidiaries, Transco Coal Gas Company, is engaged in a dispute with the Internal Revenue Service (IRS) regarding the recapture of certain income tax credits associated with the construction of a coal gasification plant in North Dakota by Great Plains Gasification Associates, in which Transco Coal Gas Company was a partner. The IRS has taken alternative positions that allege a disposition date for purposes of tax credit recapture that is earlier than the position taken in the partnership tax return. On August 23, 2001, we filed a petition in the U.S. Tax Court to contest the adjustments to the partnership tax return proposed by the IRS. Certain settlement discussions have taken place since that date. During the fourth quarter of 2004, we determined that a reasonable settlement with the IRS could not be achieved. We filed a Motion for Summary Judgment with the Tax Court, which was heard, and denied, in January 2005. The matter was then tried before the Tax Court in February 2005. We continue to believe that the return position of the partnership is with merit. However, it is reasonably possible that the Tax Court could render an unfavorable decision that could ultimately result in estimated income taxes and interest of up to approximately $110 million in excess of the amount currently accrued.


	TAPS Quality Bank

One of our subsidiaries, Williams Alaska Petroleum, Inc. (WAPI) is actively engaged in administrative litigation being conducted jointly by the FERC and the Regulatory Commission of Alaska (RCA) concerning the Trans-Alaska Pipeline System (TAPS) Quality Bank. Primary issues being litigated include the appropriate valuation of the naphtha, heavy distillate, vacuum gas oil and residual product cuts within the TAPS Quality Bank as well as the appropriate retroactive effects of the determinations. Due to the sale of WAPI’s interests on March 31, 2004, no future Quality Bank liability will accrue but we are responsible for any liability that existed as of that date including potential liability for any retroactive payments that might be awarded in these proceedings for the period prior to March 31, 2004. The FERC and RCA presiding administrative law judges rendered their joint and individual initial decisions during the third quarter of 2004. The initial decisions set forth methodologies for determining the valuations of the product cuts under review and also approved the retroactive application of the approved methodologies for the heavy distillate and residual product cuts. Based on our computation and assessment of ultimate ruling terms that would be considered probable, we recorded an accrual of approximately $134 million in the third quarter of 2004. Interest on the Quality Bank accrual is being accrued each quarter. Because the application of certain aspects of the initial decisions are subject to interpretation, we have calculated the reasonably possible impact of the decisions, if fully adopted by the FERC and RCA, to result in additional exposure to us of approximately $32 million more than we have accrued at December 31, 2004. We filed a brief on exceptions to the initial decisions to both the FERC and RCA on November 16, 2004, and our reply briefs on February 1, 2005.

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Decisions from the Commissions will likely be issued before the end of 2005. Settlement discussions have been initiated. Absent the completion of any settlements, it is unlikely that we will be required to make any payments with respect to this matter until sometime after the Commission decisions.


	Deepwater construction litigation

In a lawsuit pending in federal court in Houston, Texas, Technip Offshore, Inc. (Technip) is seeking approximately $8.6 million from two of our subsidiaries. The suit alleges that we breached a contract for the construction of deepwater export pipelines connected to the Devils Tower Spar in the Gulf of Mexico. We have filed counterclaims seeking $4.2 million in liquidated delay damages. Each party has posted a letter of credit covering the value of the claims pending against it.


	Colorado royalty litigation

On June 27, 2002, a royalty owner in the Piceance basin of Colorado filed suit against one of our Exploration & Production subsidiaries alleging that we breached our lease agreements and violated the Colorado Deceptive Trade Practices Act (CDTA) by making various deductions from his royalty payments from 1996 to date. On August 2, 2004, the jury returned its verdict in the amount of $4.1 million for the plaintiff. The verdict included a finding under the CDTA which could have potentially tripled the damage award. On November 30, 2004, the court issued an order setting aside the plaintiff’s CDTA claims, but left intact the $4.1 million award. We are appealing the judgment to the Colorado Court of Appeals.


	San Juan basin gas entitlements

One of our Exploration & Production subsidiaries is involved in a dispute with another joint interest owner in multiple federal oil and gas units located in the San Juan basin. The dispute involves various accounting issues relating to payout determinations in these federal units and associated claims for retroactive adjustment of entitlements to gas production. We are engaged in discussions with the joint interest owner regarding proper adjustment calculations, and we have proposed to settle these disputes for approximately $11.3 million plus interest of $3 million. We continue to analyze additional claims made by the joint interest owner. These additional claims total approximately $12 million.


	Other divestiture indemnifications

Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided. At December 31, 2004, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on results of operations in the period in which the claim is made.

In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.


	*Summary*

Litigation, arbitration, regulatory matters and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel,

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currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a materially adverse effect upon our future financial position.


	*Commitments*

Power has entered into certain contracts giving it the right to receive fuel conversion services as well as certain other services associated with electric generation facilities that are currently in operation throughout the continental United States. At December 31, 2004, Power’s estimated committed payments under these contracts range from approximately $394 million to $422 million annually through 2017 and decline over the remaining five years to $57 million in 2022. Total committed payments under these contracts over the next eighteen years are approximately $6.3 billion. Total payments made under these contracts during 2004, 2003, and 2002 were $402 million, $394 million and $298 million, respectively.


Note 16.	Related party transactions


	*Lehman Brothers Holdings, Inc.*

Lehman Brothers Inc. was a related party as a result of a director that served on both our Board of Directors and Lehman Brothers Holdings, Inc.’s Board of Directors. On May 20, 2004, this director retired from our Board of Directors. In third-quarter 2002, RMT, a wholly owned subsidiary, entered into a $900 million short-term Credit Agreement dated July 31, 2002, with certain lenders including a subsidiary of Lehman Brothers Inc. This debt obligation was refinanced in second-quarter 2003. Included in interest accrued on the Consolidated Statement of Operations for 2003 and 2002 are $199.4 million and $154.1 million, respectively, of interest expense, including amortization of deferred set up fees related to the RMT note. As of December 31, 2003, the amount due to Lehman Brothers, Inc., related primarily to advisory fees was $1.8 million. In addition, we paid $37.2 million and $39.6 million to Lehman Brothers Inc. in 2003 and 2002, respectively, primarily for underwriting fees related to debt and equity issuances as well as strategic advisory and restructuring success fees. We had no significant transactions with Lehman Brothers Holdings, Inc. for the year ended December 31, 2004.


	*American Electric Power Company, Inc.*

American Electric Power Company, Inc. (AEP) is a related party as a result of a director that serves on both our Board of Directors and AEP’s Board of Directors. Prior to 2003, our Power segment engaged in forward and physical power and gas trading activities with AEP. During 2002, AEP disputed a settlement amount related to the liquidation of a trading position with Power. Arbitration was initiated and in 2003 AEP paid Power $90 million to resolve the dispute. There were no trading activities with AEP in 2003. Net revenues from AEP were $264.6 million in 2002. There were no significant transactions with AEP for the year ended December 31, 2004.


	*ExxonMobil Corporation*

ExxonMobil Corporation is a related party as a result of a director that serves on both our Board of Directors and ExxonMobil Corporation’s Board of Directors. Transactions with ExxonMobil Corporation result primarily from the purchase and sale of crude oil, refined products and natural gas liquids in support of crude oil, refined products and natural gas liquids trading activities as well as revenues generated from gathering and processing activities. Aggregate revenues from this customer, including those reported on a net basis in 2002, were $178.9 million, $121.8 million and $217.6 million in 2004, 2003 and 2002, respectively. Aggregate purchases from this customer were $16.7 million, $30.4 million and $15.6 million in 2004, 2003 and 2002, respectively. Amounts due from ExxonMobil were $50.6 million and $40.0 million as of December 31,

156

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2004, and 2003, respectively. There were no significant amounts due to ExxonMobil at December 31, 2004 and 2003.

157

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 17.	Accumulated other comprehensive income (loss)

The table below presents changes in the components of accumulated other comprehensive income (loss).


	Income (Loss)

				Unrealized
				Appreciation			Foreign			Minimum
	Cash Flow			(Depreciation)			Currency			Pension
	Hedges			On Securities			Translation			Liability			Total

	(Millions)
Balance at December 31, 2001	$	370.2		$	.9		$	(23.8	)	$	(2.2	)	$	345.1

2002 Change:
Pre-income tax amount		(170.7	)		5.3			(.1	)		(27.3	)		(192.8	)
Income tax benefit (provision)		65.0			(1.9	)		—			10.4			73.5
Minority interest in other comprehensive loss		.4			—			—			—			.4
Net realized loss in net loss (net of a $.7 million income tax)		—			1.2			—			—			1.2
Net reclassification into earnings of derivative instrument gains (net of a $119.2 million income tax)		(193.6	)		—			—			—			(193.6	)

		(298.9	)		4.6			(.1	)		(16.9	)		(311.3	)

Balance at December 31, 2002		71.3			5.5			(23.9	)		(19.1	)		33.8

2003 Change:
Pre-income tax amount		(408.8	)		2.6			77.0			18.2			(311.0	)
Income tax benefit (provision)		156.3			(1.0	)		—			(6.9	)		148.4
Net reclassification into earnings of derivative instrument losses (net of a $9.7 million income tax benefit)		15.6			—			—			—			15.6
Realized gains on securities reclassified into earnings (net of a $5.3 million income tax)		—			(9.0	)		—			—			(9.0	)
Reclassification into earnings due to sale of Bio-energy facilities		—			—			—			1.2			1.2

		(236.9	)		(7.4	)		77.0			12.5			(154.8	)

Balance at December 31, 2003		(165.6	)		(1.9	)		53.1			(6.6	)		(121.0	)

2004 Change:
Pre-income tax amount		(460.9	)		(2.4	)		15.8			3.0			(444.5	)
Income tax benefit (provision)		176.5			.9			—			(1.2	)		176.2
Net reclassification into earnings of derivative instrument losses (net of a $87.8 million income tax benefit)		141.7			—			—			—			141.7
Realized losses on securities reclassified into earnings (net of a $2.1 million income tax)		—			3.4			—			—			3.4

		(142.7	)		1.9			15.8			1.8			(123.2	)

Balance at December 31, 2004	$	(308.3	)	$	—		$	68.9		$	(4.8	)	$	(244.2	)

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Available for sale securities*

During 2004, we received proceeds totaling $851.4 million from the sale and maturity of available for sale securities. We realized losses of $5.5 million from these transactions. As of December 31, 2004, all available for sale securities have matured or have been sold.

During 2003, we received proceeds totaling $370.5 million from the sale and maturity of available for sale securities. We realized gross gains and losses of $14.4 million and $0.1 million, respectively, from these transactions. At December 31, 2003, we held U.S. Treasury securities with a fair value of $381.3 million. Gross unrealized losses of $3 million on these securities are included in Accumulated Other Comprehensive Income (Loss) at December 31, 2003.


Note 18.	Segment disclosures


	*Segments and reclassification of operations*

Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different technology, marketing strategies and industry knowledge. Other primarily consists of corporate operations and certain continuing operations that were included within the previously reported International and Petroleum Services segments.

Due in part to FERC Order 2004, management and decision-making control of certain activities were transferred from our Midstream segment. Certain regulated gas gathering assets were transferred from our Midstream segment to our Gas Pipeline segment effective June 1, 2004, and our equity method investment in the Aux Sable gas processing plant and related business was transferred from our Midstream segment to our Power segment effective September 21, 2004. Consequently, the results of operations were similarly reclassified. All periods presented reflect these classifications.


	*Segments — performance measurement*

We currently evaluate performance based on segment profit (loss) from operations, which includes revenues from external and internal customers, operating costs and expenses, depreciation, depletion and amortization, equity earnings (losses) and income (loss) from investments including gains/ losses on impairments related to investments accounted for under the equity method. The accounting policies of the segments are the same as those described in Note 1, Summary of significant accounting policies. Intersegment sales are generally accounted for at current market prices as if the sales were to unaffiliated third parties.

Power entered into intercompany interest rate swaps with the corporate parent, the effect of which is included in Power’s segment revenues and segment profit (loss) as shown in the reconciliation within the following tables. The results of interest rate swaps with external counterparties are shown as interest rate swap income (loss) in the Consolidated Statement of Operations below operating income. We terminated all interest-rate derivatives in fourth quarter 2004.

The majority of energy commodity hedging by certain of our business units is done through intercompany derivatives with Power which, in turn, enters into offsetting derivative contracts with unrelated third parties. Power bears the counterparty performance risks associated with unrelated third parties. External Revenues of our Exploration & Production segment includes third party oil and gas sales, more than offset by transportation expenses and royalties due third parties on intercompany sales.

159

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following geographic area data includes revenues from external customers based on product shipment origin and long-lived assets based upon physical location.


		United States		Other		Total

		(Millions)
Revenues from external customers:
	2004	$	12,167.8	$	293.5	$	12,461.3
	2003		15,755.8		895.2		16,651.0
	2002		3,207.9		226.6		3,434.5
Long-lived assets:
	2004	$	12,149.0	$	762.0	$	12,911.0
	2003		11,982.0		776.9		12,758.9

Long-lived assets are comprised of property, plant and equipment, goodwill and other intangible assets.

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


											Midstream
					Gas			Exploration &			Gas &
		Power			Pipeline			Production			Liquids			Other			Eliminations			Total

		(Millions)
2004
Segment revenues:
	External	$	8,346.2		$	1,345.0		$	(84.0	)	$	2,844.7		$	9.4		$	—		$	12,461.3
	Internal		912.5			17.3			861.6			37.9			23.4			(1,852.7	)		—

Total segment revenues			9,258.7			1,362.3			777.6			2,882.6			32.8			(1,852.7	)		12,461.3
Less intercompany interest rate swap loss			(13.7	)		—			—			—			—			13.7			—

Total revenues		$	9,272.4		$	1,362.3		$	777.6		$	2,882.6		$	32.8		$	(1,866.4	)	$	12,461.3

Segment profit (loss)		$	76.7		$	585.8		$	235.8		$	549.7		$	(41.6	)	$	—		$	1,406.4
Less:
	Equity earnings (losses)		3.9			29.2			11.9			14.6			(9.7	)		—			49.9
	Loss from investments		—			(1.0	)		—			(17.1	)		(17.4	)		—			(35.5	)
	Intercompany interest rate swap loss		(13.7	)		—			—			—			—			—			(13.7	)

Segment operating income (loss)		$	86.5		$	557.6		$	223.9		$	552.2		$	(14.5	)	$	—			1,405.7

General corporate expenses																					(119.8	)

Consolidated operating income																				$	1,285.9

Other financial information:
Additions to long-lived assets		$	1.0		$	300.1		$	445.4		$	91.3		$	6.0		$	—		$	843.8
Depreciation, depletion & amortization		$	20.1		$	264.4		$	192.3		$	178.4		$	13.3		$	—		$	668.5
2003
Segment revenues:
	External	$	12,570.5		$	1,344.3		$	(36.3	)	$	2,740.2		$	32.3		$	—		$	16,651.0
	Internal		622.1			24.0			816.0			44.6			39.7			(1,546.4	)		—

Total segment revenues			13,192.6			1,368.3			779.7			2,784.8			72.0			(1,546.4	)		16,651.0
Less intercompany interest rate swap loss			(2.9	)		—			—			—			—			2.9			—

Total revenues		$	13,195.5		$	1,368.3		$	779.7		$	2,784.8		$	72.0		$	(1,549.3	)	$	16,651.0

Segment profit (loss)		$	135.1		$	555.5		$	401.4		$	197.3		$	(50.5	)	$	—		$	1,238.8
Less:
	Equity earnings (losses)		(4.9	)		15.8			8.9			(.8	)		1.3			—			20.3
	Income (loss) from investments		(2.4	)		0.1			—			20.1			(43.1	)		—			(25.3	)
	Intercompany interest rate swap loss		(2.9	)		—			—			—			—			—			(2.9	)

Segment operating income (loss)		$	145.3		$	539.6		$	392.5		$	178.0		$	(8.7	)	$	—			1,246.7

General corporate expenses																					(87.0	)

Consolidated operating income																				$	1,159.7

Other financial information:
Additions to long-lived assets		$	1.0		$	517.4		$	241.5		$	255.0		$	2.5		$	—		$	1,017.4
Depreciation, depletion & amortization		$	31.5		$	274.6		$	173.9		$	157.7		$	19.7		$	—		$	657.4
2002
Segment revenues:
	External	$	909.6		$	1,244.1		$	62.6		$	1,151.3		$	66.9		$	—		$	3,434.5
	Internal		(994.8	)*		57.1			797.8			32.4			57.2			50.3			—

Total segment revenues			(85.2	)		1,301.2			860.4			1,183.7			124.1			50.3			3,434.5
Less intercompany interest rate swap loss			(141.4	)		—			—			—			—			141.4			—

Total revenues		$	56.2		$	1,301.2		$	860.4		$	1,183.7		$	124.1		$	(91.1	)	$	3,434.5

Segment profit (loss)		$	(626.2	)	$	535.8		$	508.6		$	172.2		$	14.1		$	—		$	604.5
Less:
	Equity earnings (losses)		(11.1	)		88.4			3.7			19.0			(27.0	)		—			73.0
	Income (loss) from investments		(2.0	)		(13.9	)		—			—			58.0			—			42.1
	Intercompany interest rate swap loss		(141.4	)		—			—			—			—			—			(141.4	)

Segment operating income (loss)		$	(471.7	)	$	461.3		$	504.9		$	153.2		$	(16.9	)	$	—			630.8

General corporate expenses																					(142.8	)

Consolidated operating income																				$	488.0

Other financial information:
Additions to long-lived assets		$	135.8		$	705.0		$	382.8		$	616.4		$	51.7		$	—		$	1,891.7
Depreciation, depletion & amortization		$	33.1		$	253.0		$	184.6		$	149.9		$	28.2		$	—		$	648.8


*	Prior to January 1, 2003, Power intercompany cost of sales, which are netted in revenues consistent with fair-value accounting, exceed intercompany revenues. Beginning January 1, 2003, Power intercompany cost of sales are no longer netted in revenues due to the adoption of EITF Issue No. 02-3 (see Note 1).

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Total Assets						Equity Method Investments

	December 31,			December 31,			December 31,		December 31,
	2004			2003			2004		2003

	(Millions)
Power	$	8,204.1		$	8,732.9		$	45.6	$	42.8
Gas Pipeline		7,651.8			7,314.3			769.5		774.4
Exploration & Production		5,576.4			5,347.4			44.9		41.5
Midstream Gas & Liquids		4,211.7			4,050.4			273.3		289.9
Other(1)		3,584.0			6,928.7			113.2		85.1
Eliminations		(5,248.6	)		(6,078.2	)		—		—

		23,979.4			26,295.5			1,246.5		1,233.7

Net assets of discontinued operations(2)		13.6			726.3			—		—

Total assets	$	23,993.0		$	27,021.8		$	1,246.5	$	1,233.7


(1)	The decrease in Other’s total assets is primarily due to cash payments on existing debt.

(2)	The decrease in net assets of discontinued operations is due to the sale of our Canadian straddle plants during 2004.

162

THE WILLIAMS COMPANIES, INC.

QUARTERLY FINANCIAL DATA

(Unaudited)

Summarized quarterly financial data are as follows (millions, except per-share amounts). Certain amounts have been restated or reclassified as described in Note 1 of Notes to Consolidated Financial Statements.


		First			Second			Third		Fourth
		Quarter			Quarter			Quarter		Quarter

2004
Revenues		$	3,070.0		$	3,051.9		$	3,375.2	$	2,964.2
Costs and operating expenses			2,690.9			2,661.4			2,855.9		2,543.5
Income (loss) from continuing operations			—			(18.5	)		16.2		95.5
Net income (loss)			9.9			(18.2	)		98.6		73.4
Basic earnings (loss) per common share:
	Income (loss) from continuing operations		—			(.03	)		.03		.17
	Net income (loss)		.02			(.03	)		.19		.13
Diluted earnings (loss) per common share:
	Income (loss) from continuing operations		—			(.03	)		.03		.17
	Net income (loss)		.02			(.03	)		.19		.13

2003
Revenues		$	4,778.5		$	3,613.2		$	4,745.8	$	3,513.5
Costs and operating expenses			4,430.8			3,031.6			4,389.1		3,152.8
Income (loss) from continuing operations			(52.2	)		50.0			18.0		(73.3	)
Net income (loss)			(814.5	)		269.7			106.3		(53.7	)
Basic earnings (loss) per common share:
	Income (loss) from continuing operations		(.12	)		.06			.04		(.14	)
	Net income (loss)		(1.59	)		.48			.21		(.10	)
Diluted earnings (loss) per common share:
	Income (loss) from continuing operations		(.12	)		.05			.03		(.14	)
	Net income (loss)		(1.59	)		.47			.20		(.10	)

The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the average number of common shares outstanding and rounding.

Net income for fourth-quarter 2004 includes the following items which are pre-tax:


	•	$93.6 million income from Gulf Liquids insurance arbitration award and related interest income of $9.6 million at Midstream (see Note 4);

	•	$11.8 million expense related to an environmental accrual for the Augusta refinery facility, included in Other (see Note 4);

	•	$16.9 million impairment of our investment in Discovery Pipeline at Midstream (see Note 3); and

	•	$29.5 million costs associated with the FELINE PACS exchange and remarketing (see Note 11).

Net income for third-quarter 2004 includes the following items which are pre-tax:


	•	$16.5 million reduction of revenue attributable to the second quarter of 2004 as a result of Midstream’s correction of their revenue recognition methodology related to the Devils Tower facility;

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THE WILLIAMS COMPANIES, INC.

QUARTERLY FINANCIAL DATA — (Continued)

(Unaudited)


	•	$155.1 million premiums, fees and expenses related to the third-quarter 2004 cash tender offer and consent solicitations (see Note 11);

	•	$15.7 million impairment of an international cost-based investment, included at Other (see Note 3);

	•	$127.0 million loss from discontinued operations (see Note 2); and

	•	$192.9 million gain from discontinued operations for impairments and net gains on sales (see Note 2).

Net loss for second-quarter 2004 includes the following items which are pre-tax:


	•	$9.0 million charge resulting from the write-off of previously capitalized costs on an idled segment of a pipeline at Gas Pipelines (see Note 4);

	•	$10.1 million benefit from the reversal of a default reserve on good faith negotiations at Power;

	•	$11.3 million expense related to a loss provision regarding an ownership dispute on prior period production at Exploration & Production (see Note 4);

	•	$10.8 million impairment of our investment in Longhorn at Other (see Note 3);

	•	$16.5 million increase in revenues related to the Devils Tower facility subsequently reversed in third-quarter 2004 due to a revenue recognition methodology correction at Midstream; and

	•	$96.8 million premiums, fees and expenses related to the second-quarter 2004 cash tender offer (see Note 11).

Net income for first-quarter 2004 includes the following items which are pre-tax:


	•	$13.0 million charge resulting from the termination of a non-derivative power sales contract at Power;

	•	$6.5 million net unreimbursed Longhorn recapitalization advisory fees (see Note 3);

	•	$8.7 million income from discontinued operations (see Note 2); and

	•	$6.9 million gain from discontinued operations for impairments and net gains on sales (see Note 2).

Net loss for fourth-quarter 2003 includes the following items which are pre-tax:


	•	$45.0 million impairment of goodwill at Power (see Note 4);

	•	$44.1 million impairment of the Hazelton generation facility at Power (see Note 4);

	•	$33.3 million California rate refund and other accrual adjustments at Power;

	•	$19.9 million in unrealized gains on certain derivative contracts that had previously not been recognized in 2003, including approximately $10 million of revenue related to the accounting treatment applied to certain derivative contracts terminated in prior periods at Power (see Note 1);

	•	$16.2 million gain on sale of the wholesale propane business at Midstream (see Note 4);

	•	$66.8 million of costs for the early retirement of debt (see Note 11);

	•	$16.4 million impairment of the Gulf Liquids operations at Midstream (see Note 4); and

	•	$32.5 million income from discontinued operations (see Note 2).

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THE WILLIAMS COMPANIES, INC.

QUARTERLY FINANCIAL DATA — (Continued)

(Unaudited)

Net income for third-quarter 2003 includes the following items which are pre-tax:


	•	$13.0 million gain on sale of a full requirements contract at Power (see Note 4);

	•	$126.8 million positive valuation adjustment on a terminated derivative contract at Power;

	•	$13.5 million gain on sale of marketable equity securities at Power (see Note 3);

	•	$11.0 million gain on sale of equity interest in West Texas LPG Pipeline, L.P. investment at Midstream (see Note 3);

	•	$20.3 million income from discontinued operations (see Note 2); and

	•	$72.0 million gain from discontinued operations for impairments and net gains on sales (see Note 2).

Net income for second-quarter 2003 includes the following items which are pre-tax:


	•	$20 million CFTC settlement at Power (see Note 4);

	•	$175 million gain on sale of a full requirements contract at Power (see Note 4);

	•	$25.5 million write-off of software development costs at Gas Pipelines (see Note 4);

	•	$80.7 million correction, attributable to prior periods relating to the accounting treatment previously applied to certain third party derivative contracts during 2002 and 2001 at Power (see Note 1);

	•	$12.4 million of revenue attributable to prior periods relating to the accounting treatment previously applied to certain third party derivative contracts during 2002 and 2001 and recorded prior to the $80.7 million correction in second-quarter at Power (see Note 1);

	•	$94.1 million gain on the sale of certain natural gas properties at Exploration & Production (see Note 4);

	•	$42.4 million impairment of an investment in equity and debt securities of Longhorn Partners Pipeline L.P. at Other (see Note 3);

	•	$14.5 million in accelerated amortization of costs related to the termination of the revolving credit agreement;

	•	$13.5 million impairment of cost based investment in ReserveCo, a company holding phosphate reserves (see Note 3);

	•	$92.6 million impairment of the Gulf Liquids operations at Midstream (see Note 4);

	•	$33.3 million income from discontinued operations (see Note 2); and

	•	$325.5 million gain from discontinued operations for impairments and net gains on sales (see Note 2).

Net loss for first-quarter 2003 includes the following items which are pre-tax:


	•	$13.7 million of revenue attributable to prior periods relating to the accounting treatment previously applied to certain third party derivative contracts during 2002 and 2001 and recorded prior to the $80.7 million correction in second-quarter at Power (see Note 1);

	•	$12.0 million impairment of a cost based investment in Algar Telecom S.A. at Other (see Note 3);

	•	$761.3 million after tax cumulative effect of change in accounting principles related to the adoption of EITF 02-3 and SFAS No. 143 (see Note 1);

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THE WILLIAMS COMPANIES, INC.

QUARTERLY FINANCIAL DATA — (Continued)

(Unaudited)


	•	$111.8 million income from discontinued operations (see Note 2); and

	•	$117.3 million loss from discontinued operations for impairments and net losses on sales (see Note 2).

166

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES

(Unaudited)

The following information pertains to our oil and gas producing activities and is presented in accordance with SFAS No. 69, “Disclosures About Oil and Gas Producing Activities.” The information is required to be disclosed by geographic region. We have significant oil and gas producing activities primarily in the Rocky Mountain and Mid-continent areas of the United States. Additionally, we have oil and gas producing activities in Argentina and Venezuela. However, proved reserves and revenues related to these activities are approximately 6.7 percent and 5.2 percent, respectively, of our total international and domestic oil and gas producing activities. The following information relates only to the oil and gas activities in the United States and includes the activities of those properties that qualified for reporting as discontinued operations in the Consolidated Statement of Operations.

Capitalized costs


	As of December 31,

	2004			2003

	(Millions)
Proved properties	$	3,022.9		$	2,464.4
Unproved properties		569.7			682.5

		3,592.6			3,146.9
Accumulated depreciation, depletion and amortization and valuation provisions		(688.3	)		(511.1	)

Net capitalized costs	$	2,904.3		$	2,635.8


	•	Capitalized costs include the cost of equipment and facilities for oil and gas producing activities. These amounts for 2004 and 2003 do not include approximately $1 billion of goodwill related to the purchase of Barrett Resources Corp. (Barrett) in 2001.

	•	Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and successful exploratory wells and related equipment and facilities.

	•	Unproved properties consist primarily of acreage related to probable/possible reserves acquired through the Barrett acquisition in addition to a small portion of unproved exploratory acreage.

Costs incurred


	For the Year Ended
	December 31,

	2004		2003		2002

	(Millions)
Acquisition	$	17.2	$	11.3	$	—
Exploration		4.5		7.1		15.5
Development		419.2		186.8		374.3

	$	440.9	$	205.2	$	389.8


	•	Costs incurred include capitalized and expensed items.

	•	Acquisition costs are as follows: The 2004 costs related to the Huber-Edwards reserve acquisition in the San Juan Basin, RBS, Vectra and Citrus reserve acquisitions in the Arkoma basin, and Guthrie leasehold acquisition in the Powder River basin. The 2003 costs relates to the Smith, Contra, Tailwind acquisition also in the Arkoma basis at the end of 2003.

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THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)

(Unaudited)


	•	Exploration costs include the costs of geological and geophysical activity, drilling and equipping exploratory wells determined to be dry holes, and the cost of retaining undeveloped leaseholds.

	•	Development costs include costs incurred to gain access to and prepare development well locations for drilling and to drill and equip development wells.

Results of operations


			For the Year Ended December 31,

			2004			2003			2002*

			(Millions)
Revenues:
	Oil and gas revenues		$	599.9		$	611.9		$	683.0
	Other revenues			137.3			168.8			189.0

		Total revenues		737.2			780.7			872.0

Costs:
	Production costs			165.4			138.3			119.5
	General & administrative			58.3			54.4			62.9
	Exploration expenses			4.5			7.1			13.9
	Depreciation, depletion & amortization			183.4			170.2			191.0
	Property impairments			—			—			8.4
	(Gains)/losses on sales of interests in oil and gas properties			0.1			(134.8	)		(141.7	)
	Other expenses			115.2			102.1			109.2

		Total costs		526.9			337.3			363.2

Results of operations				210.3			443.4			508.8
Provision for income taxes				(81.4	)		(169.6	)		(186.9	)

Exploration and production net income			$	128.9		$	273.8		$	321.9


*	Certain amounts have been reclassified to conform to current presentation.


	•	Results of operations for producing activities consist of all related domestic activities within the Exploration & Production reporting unit, including those operations that qualified for presentation as discontinued operations within our Consolidated Statement of Operations. Included above are the pretax results of operations and gains on sales of assets, reported as discontinued operations, of $60.2 million in 2003 and $11.9 million in 2002. Other expenses in 2004 includes a $16 million gain attributable to the sales of securities, assicatied with a coal seam royalty trust, that were purchased for resale.

	•	Oil and gas revenues consist primarily of natural gas production sold to the Power subsidiary and includes the impact of intercompany hedges.

	•	Other revenues and other expenses consist of activities within the Exploration & Production segment that are not a direct part of the producing activities. These non-producing activities include acquisition and disposition of other working interest and royalty interest gas and the movement of gas from the wellhead to the tailgate of the respective plants for sale to the Power subsidiary or third party purchasers. In addition, other revenues include recognition of income from transactions which transferred certain non-operating benefits to a third party.

168

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)

(Unaudited)


	•	Production costs consist of costs incurred to operate and maintain wells and related equipment and facilities used in the production of petroleum liquids and natural gas. These costs also include production related taxes other than income taxes, and administrative expenses related to the production activity. Excluded are depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.

	•	Exploration expenses include unsuccessful exploratory dry hole costs, leasehold impairment, geological and geophysical expenses and the cost of retaining undeveloped leaseholds.

	•	Depreciation, depletion and amortization includes depreciation of support equipment.

Proved reserves


		2004			2003			2002

		(Bcfe)
Proved reserves at beginning of period			2,703			2,834			3,178
	Revisions		(70	)		(5	)		(87	)
	Purchases		24			38			—
	Extensions and discoveries		521			412			385
	Production		(191	)		(186	)		(211	)
	Sale of minerals in place		(1	)		(390	)		(431	)

Proved reserves at end of period			2,986			2,703			2,834

Proved developed reserves at end of period			1,348			1,165			1,368


	•	The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as the 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 from known reservoirs under existing economic and operating conditions. Our proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled or where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.

	•	Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit. Crude oil reserves are insignificant and have been included in the proved reserves on a basis of billion cubic feet equivalents (Bcfe).

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves

The following is based on the estimated quantities of proved reserves and the year-end prices and costs. The average year end natural gas prices used in the following estimates were $5.08, $5.28, and $3.85 per MMcfe at December 31, 2004, 2003 and 2002, respectively. Future income tax expenses have been computed considering available carryforwards and credits and the appropriate statutory tax rates. The discount rate of 10 percent is as prescribed by SFAS No. 69. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes

169

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)

(Unaudited)

available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs. Of the $1,703 million of future development costs, $421 million, $461 million and $374 million are estimated to be spent in 2005, 2006 and 2007, respectively.

Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.

Standardized measure of discounted future net cash flows


		At December 31,

		2004		2003

		(Millions)
Future cash inflows		$	15,174	$	14,268
Less:
	Future production costs		3,027		2,434
	Future development costs		1,703		1,303
	Future income tax provisions		3,744		3,858

Future net cash flows			6,700		6,673
Less 10 percent annual discount for estimated timing of cash flows			3,553		3,324

Standardized measure of discounted future net cash flows		$	3,147	$	3,349

170

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES — (Continued)

(Unaudited)

Sources of change in standardized measure of discounted future net cash flows


		2004			2003			2002

		(Millions)
Standardized measure of discounted future net cash flows beginning of period		$	3,349		$	2,272		$	1,432
Changes during the year:
	Sales of oil and gas produced, net of operating costs		(835	)		(567	)		(322	)
	Net change in prices and production costs		(306	)		2,001			1,602
	Extensions, discoveries and improved recovery, less estimated future costs		787			901			546
	Development costs incurred during year		419			187			374
	Changes in estimated future development costs		(696	)		(159	)		(326	)
	Purchase of reserves in place, less estimated future costs		29			78			—
	Sales of reserves in place, less estimated future costs		(3	)		(855	)		(611	)
	Revisions of previous quantity estimates		(90	)		(11	)		(123	)
	Accretion of discount		286			341			203
	Net change in income taxes		182			(773	)		(537	)
Other			25			(66	)		34

Net changes			(202	)		1,077			840

Standardized measure of discounted future net cash flows end of period		$	3,147		$	3,349		$	2,272

171

THE WILLIAMS COMPANIES, INC.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS


					ADDITIONS

					Charged to
			Beginning		Cost and									Ending
			Balance		Expenses			Other			Deductions			Balance

			(Millions)
Year ended December 31, 2004:
	Allowance for doubtful accounts — Accounts and notes receivable(a)		$	112.2	$	(.8	)	$	—		$	12.6	(c)	$	98.8
	Price-risk management credit reserves(a)			39.8		(12.8	)(e)		(.6	)		—			26.4
	Processing plant major maintenance accrual(b)			4.1		1.6			—			—			5.7
Year ended December 31, 2003:
	Allowance for doubtful accounts — Accounts and notes receivable(a)			111.8		7.3			7.9	(g)		14.8	(c)		112.2
	Price-risk management credit reserves(a)			250.4		2.6	(e)		—			213.2	(f)		39.8
	Processing plant major maintenance accrual(b)			2.7		1.4			—			—			4.1
Year ended December 31, 2002:
	Allowance for doubtful accounts — Accounts and notes receivable(a)			251.8		22.4			—			162.4	(c)		111.8
		Other noncurrent assets(a)		103.2		256.0			1,720.0	(d)		2,079.2	(c)		—
	Price-risk management credit reserves(a)			648.2		(397.8	)(e)		—			—			250.4
	Processing plant major maintenance accrual(b)			1.2		1.5			—			—			2.7


(a)		Deducted from related assets.

(b)		Included in liabilities.

(c)		Represents balances written off, net of recoveries and reclassifications.

(d)		Reflects a reclassification of amounts included in the liability for Guarantees and payment obligations related to WilTel at December 31, 2002.

(e)		Included in revenue.

(f)		Reflects cumulative effect of change in accounting principle related to EITF 02-3 (see Note 1 of Notes to Consolidated Financial Statements).

(g)		Reflects allowances for accounts receivable charged to costs and expenses for a discontinued operation whose receivables were not held for sale.

172


Item 9.	*Changes in and Disagreements with Accountants on Accounting and Financial Disclosure*

None


Item 9A.	*Controls and Procedures*

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15(d) — 15(e) of the Securities Exchange Act of 1934) (Disclosure Controls) was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our Disclosure Controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

Management’s Report on Internal Control over Financial Reporting

See “Management’s Report on Internal Control over Financial Reporting” set forth on page 88 in Item 8, Financial Statements and Supplementary Data, immediately following the audit reports of Ernst & Young LLP.

Fourth Quarter 2004 Changes in Internal Control Over Financial Reporting

Effective October 1, 2004, our Power business segment elected to apply to certain of its derivatives hedge accounting provisions of FAS 133 (see Note 14 of Notes to Financial Statements). In connection with this application, Power implemented certain changes to its processes and established related internal controls.

There has been no material change in our Internal Controls, other than those noted above, that occurred during the registrant’s fourth fiscal quarter.


Item 9B.	*Other Information*

None.

PART III


Item 10.	*Directors and Executive Officers of the Registrant*

The information regarding our directors and nominees for director required by Item 401 of Regulation S-K will be presented under the headings “Board of Directors — Board Committees”, “Election of Directors”, and “Principal Accountant Fees and Services” in our Proxy Statement prepared for the solicitation

173

of proxies in connection with our Annual Meeting of Stockholders to be held May 19, 2005 (Proxy Statement), which information is incorporated by reference herein.

Information regarding our executive officers required by Item 401 of Regulation S-K is presented as Item 4A herein and captioned as permitted by General Instruction G(3) to Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K.

Information required by Item 405 of Regulation S-K will be included under the heading “Compliance with Section 16(a) of the Securities Exchange Act of 1934” in our Proxy Statement, which information is incorporated by reference herein.

We have adopted a Code of Ethics that applies to our Chief Executive Officer, Chief Financial Officer, and Controller, or persons performing similar functions. The Code of Ethics, together with our Corporate Governance Guidelines, the charters for each of our board committees, and our Code of Business Conduct applicable to all employees are available on our Internet website at http://www.williams.com. We will provide, free of charge, a copy of our Code of Ethics or any of our other corporate documents listed above upon written request to our Secretary at Williams, One Williams Center, Suite 4100, Tulsa, Oklahoma 74172. We intend to disclose any amendments to or waivers of the Code of Ethics on behalf of our Chief Executive Officer, Chief Financial Officer, Controller, and persons performing similar functions on our Internet website at http://www.williams.com under the Investor Relations caption, promptly following the date of any such amendment or waiver.


Item 11.	*Executive Compensation*

The information required by Item 402 of Regulation S-K regarding executive compensation will be presented under the headings “Board of Directors” and “Executive Compensation and Other Information” in our Proxy Statement, which information is incorporated by reference herein. Notwithstanding the foregoing, the information provided under the headings “Compensation Committee Report on Executive Compensation” and “Stockholder Return Performance Presentation” in our Proxy Statement is not incorporated by reference herein.


Item 12.	*Security Ownership of Certain Beneficial Owners and Management*

The information regarding the security ownership of certain beneficial owners and management required by Item 403 of Regulation S-K will be presented under the headings “Security Ownership of Certain Beneficial Owners and Management” in our Proxy Statement, which information is incorporated by reference herein.

174

EQUITY COMPENSATION STOCK PLANS

Securities authorized for issuance under equity compensation plans

The following table provides information concerning our common stock that may be issued upon the exercise of options, warrants and rights under all of our existing equity compensation plans as of December 31, 2004, including The Williams Companies, Inc. 2002 Incentive Plan, The Williams Companies, Inc. 2001 Stock Plan, The Williams Companies, Inc. Stock Plan for Non-Officer Employees, The Williams Companies, Inc. 1996 Stock Plan, The Williams International Stock Plan, The Williams Companies, Inc. 1996 Stock Plan for Non-Employee Directors, The Williams Companies, Inc. 1988 Stock Option Plan for Non-Employee Directors, The Williams Companies, Inc. 1990 Stock Plan and The Williams Communications Stock Plan.

Number of Securities

Number of Securities to

Weighted-Average

Remaining Available for Future

be Issued upon Exercise

Exercise Price of

Issuance Under Equity

of Outstanding Options,

Outstanding Options,

Compensation Plans

Warrants and

(Excluding Securities Reflected

Plan Category

Rights(2)

Rights(3)

in the 1st Column of This Table)

Equity Compensation plans approved by security holders

19,702,328

12.44

25,235,521

Equity Compensation plans not approved by security holders(1)

4,832,815

26.51

Total

24,535,143

15.36

25,235,521


(1)	As described in Note 13 of our Notes to Consolidated Financial Statements, these plans were terminated upon shareholder approval of the 2002 Incentive Plan. Options outstanding in these plans remain in the plans subject to their terms. Those options generally expire 10 years after the grant date.

(2)	Includes 2,530,844 shares of deferred stock.

(3)	Excludes the shares of deferred stock included in the 1st column of this table for which there is no weighted-average price.


Item 13.	*Certain Relationships and Related Transactions*

The information regarding certain relationships and related transactions required by Item 404 of Regulation S-K will be presented under the heading “Certain Relationships and Related Transactions” in our Proxy Statement, which information is incorporated by reference herein.


Item 14.	*Principal Accounting Fees and Services*

The information regarding our principal accountant fees and services required by Item 9(e) of Schedule 14A will be presented under the heading “Principal Accountant Fees and Services” in our Proxy Statement, which information is incorporated by reference herein.

175

PART IV


Item 15.	*Exhibits, Financial Statement Schedules*

(a) 1 and 2.


			Page

Covered by report of independent auditors:
	Consolidated statement of operations for each of the three years ended December 31, 2004			91
	Consolidated balance sheet at December 31, 2004 and 2003			92
	Consolidated statement of stockholders’ equity for each of the three years ended December 31, 2004			93
	Consolidated statement of cash flows for each of the three years ended December 31, 2004			94
	Notes to consolidated financial statements			95
Not covered by report of independent auditors:
	Quarterly financial data (unaudited)			163
	Supplemental oil and gas disclosures (unaudited)			167
	Schedule for each of the three years ended December 31, 2004:
		II — Valuation and qualifying accounts		172

All other schedules have been omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and notes thereto.

(a) 3 and (b). The exhibits listed below are filed as part of this annual report.

INDEX TO EXHIBITS


Exhibit
No.			Description

	3.1	—	Restated Certificate of Incorporation, as supplemented.
	3.2*	—	Restated By-laws (filed as Exhibit 3.1 to Form 8-K filed September 21, 2004 ).
	4.1*	—	Form of Senior Debt Indenture between Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4.1 to Form S-3 filed September 8, 1997).
	4.2*	—	Form of Floating Rate Senior Note (filed as Exhibit 4.3 to Form S-3 filed September 8, 1997).
	4.3*	—	Form of Fixed Rate Senior Note (filed as Exhibit 4.4 to Form S-3 filed September 8, 1997).
	4.4*	—	Fourth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed as Exhibit 4(j) to Form 10-K for the fiscal year ended December 31, 2000).
	4.5*	—	Fifth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed as Exhibit 4(k) to Form 10-K for the fiscal year ended December 31, 2000).
	4.6*	—	Sixth Supplemental Indenture dated January 14, 2002, between Williams and Bank One Trust Company, National Association, as Trustee (filed as Exhibit 4.1 to Form 8-K filed January 23, 2002).
	4.7*	—	Seventh Supplemental Indenture dated March 19, 2002, between The Williams Companies, Inc. as Issuer and Bank One Trust Company, National Association, as Trustee (filed as Exhibit 4.1 to Form 10-Q filed May 9, 2002).

176


Exhibit
No.			Description

	4.8*	—	Eighth Supplemental Indenture dated as of June 3, 2002, between The Williams Companies, Inc., as Issuer and Bank One Trust Company, N.A., as Trustee (filed as Exhibit 4.8 to Form 10-K for the fiscal year ended December 31, 2003).
	4.9*	—	Ninth Supplemental Indenture dated June 10, 2003 between The Williams Companies, Inc. as Issuer and JPMorgan Chase Bank as Trustee (filed as Exhibit 4.1 to Form 10-Q filed August 12, 2003).
	4.10*	—	Tenth Supplemental Indenture dated as of August 17, 2004, with respect to the Indenture dated as of November 10, 1997 between The Williams Companies, Inc. and JPMorgan Chase Bank (as successor trustee to Bank One Trust Company, National Association (successor to the First National Bank of Chicago)) (filed as Exhibit 99.2 for Form 8-K filed August 17, 2004).
	4.11*	—	Form of Senior Debt Indenture between Williams Holdings of Delaware, Inc. and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Williams Holdings of Delaware, Inc.’s Form 10-Q filed October 18, 1995).
	4.12*	—	First Supplemental Indenture dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams and Citibank, N.A., as Trustee (filed as Exhibit 4(o) to Form 10-K for the fiscal year ended December 31, 1999).
	4.13*	—	Senior Indenture dated February 25, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4.4.1 to MAPCO Inc.’s Amendment No. 1 to Form S-3 dated February 25, 1997).
	4.14*	—	Supplemental Indenture No. 1 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(o) to MAPCO Inc.’s Form 10-K for the fiscal year ended December 31, 1997).
	4.15*	—	Supplemental Indenture No. 2 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(p) to MAPCO Inc.’s Form 10-K for the fiscal year ended December 31, 1997).
	4.16*	—	Supplemental Indenture No. 3 dated March 31, 1998, among MAPCO Inc., Williams Holdings of Delaware, Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(j) to Williams Holdings of Delaware, Inc.’s Form 10-K for the fiscal year ended December 31, 1998).
	4.17*	—	Supplemental Indenture No. 4 dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(q) to Form 10-K for the fiscal year ended December 31, 1999).
	4.18*	—	Revised Form of Indenture between Barrett Resources Corporation, as Issuer, and Bankers Trust Company, as Trustee, with respect to Senior Notes including specimen of 7.55% Senior Notes (filed as Exhibit 4.1 to Barrett Resources Corporation’s Amendment No. 2 to Registration Statement on Form S-3 filed February 10, 1997).
	4.19*	—	First Supplemental Indenture dated 2001, between Barrett Resources Corporation, as Issuer, and Bankers Trust Company, as Trustee (filed as Exhibit 4.3 to Form 10-Q filed November 13, 2001).
	4.20*	—	Second Supplemental Indenture dated as of August 2, 2001, among Barrett Resources Corporation, as Issuer, Resources Acquisition Corp., The Williams Companies, Inc. and Bankers Trust Company, as Trustee (filed as Exhibit 4.4 to Form 10-Q filed November 13, 2001).
	4.21*	—	Third Supplemental Indenture dated as of May 20, 2004 with respect to the Indenture dated as of February 1, 1997 between Barrett Resources Corporation (predecessor-in-interest to Williams Production RMT Company) and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee (filed as Exhibit 99.2 to Form 8-K filed May 20, 2004).
	4.22*	—	Form of Note (filed as Exhibit 4.2 and included in Exhibit 4.1 to Form 8-K filed January 23, 2002).
	4.23*	—	Purchase Contract Agreement dated January 14, 2002, between Williams and JPMorgan Chase Bank, as Purchase Contract Agent (filed as Exhibit 4.3 to Form 8-K filed January 23, 2002).
	4.24*	—	Form of Income PACS Certificate (filed as Exhibit 4.4 and included in Exhibit 4.3 to Form 8-K filed January 23, 2002).

177


Exhibit
No.			Description

	4.25*	—	Pledge Agreement dated January 14, 2002, among Williams, Bank, as Purchase Contract Agent (filed as Exhibit 4.5 to Form 8-K filed January 23, 2002).
	4.26*	—	Remarketing Agreement dated January 14, 2002, among Williams, JPMorgan Chase Bank, as Purchase Contract Agent, and Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Remarketing Agent (filed as Exhibit 4.6 to Form 8-K filed January 23, 2002).
	4.27*	—	Supplemental Remarketing Agreement dated as of November 4, 2004 by and among Williams, Merill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporation, as Remarketing Agent, and JPMorgan Chase Bank, as Purchase Contract Agent (filed as exhibit 99.1 to Form 8-K filed November 9, 2004).
	4.28*	—	Indenture dated March 4, 2003, between Northwest Pipeline Corporation and JP Morgan Chase Bank, as Trustee (filed as Exhibit 4.1 to Form 10-Q filed May 13, 2003.
	4.29*	—	Indenture dated as of May 28, 2003, by and between The Williams Companies, Inc. and JPMorgan Chase Bank, as Trustee for the issuance of the 5.50% Junior Subordinated Convertible Debentures due 2033 (filed as Exhibit 4.2 to Form 10-Q filed August 12, 2003).
	4.30*	—	Amended and Restated Rights Agreement dated September 21, 2004 by and between The Williams Companies, Inc. and EquiServe Trust Company, N.A., as Rights Agent (filed as Exhibit 4.1 to Form 8-K filed September 21, 2004.
	10.1*	—	The Williams Companies, Inc. Supplemental Retirement Plan effective as of January 1, 1988 (filed as Exhibit 10(iii)(c) to Form 10-K for the fiscal year ended December 31, 1987).
	10.2*	—	First Amendment to The Williams Companies, Inc. Supplemental Retirement Plan effective as of April 1, 1988 (filed as Exhibit 10.2 to Form 10-K for the fiscal year ended December 31, 2003).
	10.3	—	Second Amendment to The Williams Companies, Inc. Supplemental Retirement Plan effective as of January 1, 2002 and January 1, 2003.
	10.4*	—	The Williams Companies, Inc. 1988 Stock Option Plan for Non-Employee Directors (filed as Exhibit A to the Proxy Statement dated March 14, 1988).
	10.5*	—	The Williams Companies, Inc. 1990 Stock Plan (filed as Exhibit A to the Proxy Statement dated March 12, 1990).
	10.6*	—	The Williams Companies, Inc. Stock Plan for Non-Officer Employees (filed as Exhibit 10(iii)(g) to Form 10-K for the fiscal year ended December 31, 1995).
	10.7*	—	The Williams Companies, Inc. 1996 Stock Plan (filed as Exhibit A to the Proxy Statement dated March 27, 1996).
	10.8*	—	The Williams Companies, Inc. 1996 Stock Plan for Non-Employee Directors (filed as Exhibit B to the Proxy Statement dated March 27, 1996).
	10.9*	—	Indemnification Agreement effective as of August 1, 1986, among Williams, members of the Board of Directors and certain officers of Williams (filed as Exhibit 10(iii)(e) to Form 10-K for the year ended December 31, 1986).
	10.10*	—	The Williams International Stock Plan (filed as Exhibit 10(iii)(l) to Form 10-K for the fiscal year ended December 31, 1998).
	10.11*	—	Form of Stock Option Secured Promissory Note and Pledge Agreement among Williams and certain employees, officers and non-employee directors (filed as Exhibit 10(iii)(m) to Form 10-K for the fiscal year ended December 31, 1998).
	10.12	—	Form of 2004 Deferred Stock Agreement among Williams and certain employees and officers.
	10.13	—	Form of 2004 Performance-Based Deferred Stock Agreement among Williams and executive officers.
	10.14*	—	Form of Stock Option Agreement among Williams and certain employees and officers (filed as Exhibit 99.1 to Form 8-K filed March 2, 2005).
	10.15*	—	Form of 2005 Deferred Stock Agreement among Williams and certain employees and officers (filed as Exhibit 99.2 to Form 8-K filed March 2, 2005).
	10.16*	—	Form of 2005 Performance-Based Deferred Stock Agreement among Williams and executive officers.(filed as Exhibit 99.3 to Form 8-K filed March 2, 2005).

178


Exhibit
No.			Description

	10.17*	—	The Williams Companies, Inc. 2001 Stock Plan (filed as Exhibit 4.1 to Form S-8 filed August 1, 2001).
	10.18*	—	The Williams Companies, Inc. 2002 Incentive Plan as amended and restated effective as of January 23, 2004 (filed as Exhibit 10.1 to Form 10-Q filed on August 5, 2004).
	10.19*	—	Form of Change in Control Severance Agreement between the Company and certain executive officers (filed as Exhibit 10.12 to Form 10-Q filed November 14, 2002).
	10.20*	—	Settlement Agreement, by and among the Governor of the State of California and the several other parties named therein and The Williams Companies, Inc. and Williams Energy Marketing & Trading Company dated November 11, 2002 (filed as Exhibit 10.79 for Form 10-K for the fiscal year ended December 31, 2002).
	10.21*	—	U.S. $500,000,000 Term Loan Agreement among Williams Production Holdings LLC, Williams Production RMT Company, as Borrower, the Several Lenders from time to time parties thereto, Lehman Brothers Inc. and Banc of America Securities LLC as Joint Lead Arrangers, Citigroup USA, Inc. and JPMorgan Chase Bank, as Co-Syndication Agents, Bank of America, N.A., as Documentation Agent, and Lehman Commercial Paper Inc., as Administrative Agent dated as of May 30, 2003 (filed as Exhibit 10.1 to Form 10-Q filed August 12, 2003).
	10.22*	—	The First Amendment to the Term Loan Agreement dated February 25, 2004, between Williams Production Holdings, LLC, Williams Production RMT Company, as Borrower, the several financial institutions as lenders and Lehman Commercial Paper Inc., as Administrative Agent dated as of May 30, 2003 (filed as Exhibit 10.3 to Form 10-Q filed May 6, 2004).
	10.23*	—	Guarantee and Collateral Agreement made by Williams Production Holdings LLC, Williams Production RMT Company and certain of its Subsidiaries in favor of Lehman Commercial Paper Inc. as Administrative Agent dated as of May 30, 2003 (filed as Exhibit 10.2 to Form 10-Q filed August 12, 2003).
	10.24*	—	U.S. $800,000,000 Credit Agreement dated as of June 6, 2003, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, as Borrowers, Citibank, N.A., as Administrative Agent and Collateral Agent, Bank of America, N.A., as Syndication Agent, JPMorgan Chase Bank, as documentation Agreement, Citibank, N.A. and Bank of America, N.A. as Issuing Banks, the banks named therein as Banks and Citigroup Global Markets Inc. and Banc of America Securities LLC as Joint Lead Arrangers and Joint Book Runners (filed as Exhibit 10.3 to Form 10-Q filed August 12, 2003).
	10.25*	—	Security Agreement dated as of June 6, 2003, among The Williams Companies, Inc., as Grantor, Citibank, N.A., as Collateral Agent and Citibank, N.A. as Securities Intermediary (filed as Exhibit 10.4 to Form 10-Q filed August 12, 2003).
	10.26*	—	U.S. $1,000,000,000 Credit Agreement dated as of May 3, 2004, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipeline Corporation, as Borrowers, Citicorp USA, Inc., as Administrative Agent and Collateral Agent, Citibank, N.A. and Bank of America, N.A., as Issuing Banks, the banks named therein as Banks, Bank of America, N.A., as Syndication Agent, JPMorgan Chase Bank, The Bank of Nova Scotia, The Royal Bank of Scotland plc as Co-Documentation Agents, Citigroup Global Markets Inc. and Banc of America Securities LLC as Joint Lead Arrangers and Co-Book Runners (filed as Exhibit 10.4 to Form 10-Q filed May 6, 2004).
	10.27*	—	Letter of Credit Commitment Increase Agreement dated August 4, 2004, by and among The Williams Companies, Inc., Citicorp USA in its capacity as Agent under the Credit Agreement dated as of May 3, 2004 among the Borrower, Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, the Agent, the Collateral Agent, the Banks and Issuing Banks party thereto and Citibank, N.A. and Bank of America, N.A. (filed as Exhibit 10.1 to Form 10-Q filed November 4, 2004).

179


Exhibit
No.			Description

	10.28*	—	Revolving Credit Commitment Increase Agreement dated August 4, 2004, by and among The Williams Companies, Inc., Citicorp USA in its capacity as Agent under the Credit Agreement dated as of May 3, 2004 among the Borrower, Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, the Agent, the Collateral Agent and the Banks and Issuing Banks party thereto, the Issuing Banks and Citicorp USA, Inc. (filed as Exhibit 10.2 to Form 10-Q filed November 4, 2004).
	10.29	—	Amendment Agreement dated as of October 19, 2004 among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipeline Corporation, as Borrowers, the banks, financial institutions and other institutional lenders that are parties to the Credit Agreement dated as of May 3, 2004 among the Borrowers, the Banks, Citicorp USA, Inc., as agent and Citibank, N.A. and Bank of America, N.A., as issuers of letters of credit under the Credit Agreement, the Agent and the Issuing Banks.
	10.30*	—	Western Midstream Security Agreement dated as of May 3, 2004, among Williams Gas Processing Company, Williams Field Services Company, Williams Gas Processing — Wamsutter Company as Grantors, in favor of Citicorp USA, Inc. as Collateral Agents (filed as Exhibit 10.5 to Form 10-Q filed May 6, 2004).
	10.31*	—	Pledge Agreement dated as of May 3, 2004, by Williams Field Services Group, Inc. in favor of Citicorp USA, Inc. as Collateral Agent (filed as Exhibit 10.6 to Form 10-Q filed May 6, 2004).
	10.32*	—	Western Midstream Guaranty by Williams Gas Processing Company, Williams Field Services Company, Williams Gas Processing — Wamsutter Company as Guarantors in favor of Citicorp USA, Inc. as Collateral Agent (filed as Exhibit 10.7 for Form 10-Q filed May 6, 2004).
	10.33*	—	Pipeline Holdco Guaranty by Williams Gas Pipeline Company, LLC as Guarantor in favor of Citicorp USA, Inc. as Collateral Agent (filed as Exhibit 10.8 to Form 10-Q filed May 6, 2004).
	10.34*	—	Amended and Restated U.S. $400,000,000 Five Year Credit Agreement dated April 14, 2004 and amended January 20, 2005 among The Williams Companies, Inc., as Borrower, the Initial Lenders named herein, as Initial Lenders , the Initial Issuing Banks named herein, as Initial Issuing Banks and Citibank, N.A, as Agent (filed as Exhibit 10.1 to Form 8-K filed on January 26, 2005).
	10.35*	—	Amended and Restated U.S. $100,000,000 Five Year Credit Agreement dated April 26, 2004 and amended January 20, 2005 among The Williams Companies, Inc., as Borrower, the Initial Lenders named herein, as Initial Lenders , the Initial Issuing Banks named herein, as Initial Issuing Banks and Citibank, N.A, as Agent (filed as Exhibit 10.2 to Form 8-K filed on January 26, 2005).
	10.36*	—	U.S. $400,000,000 Five Year Credit Agreement dated January 20, 2005 among The Williams Companies, Inc., as Borrower, the Initial Lenders named herein, as Initial Lenders, the Initial Issuing Banks named herein, as Initial Issuing Banks and Citibank, N.A, as Agent (filed as Exhibit 10.3 to Form 8-K filed on January 26, 2005).
	10.37*	—	U.S. $100,000,000 Five Year Credit Agreement dated January 20, 2005 among The Williams Companies, Inc., as Borrower, the Initial Lenders named herein, as Initial Lenders , the Initial Issuing Banks named herein, as Initial Issuing Banks and Citibank, N.A, as Agent (filed as Exhibit 10.4 to Form 8-K filed on January 26, 2005).
	10.38*	—	New Omnibus Agreement among WEG Acquisitions, L.P., Williams Energy Services, LLC, Williams Natural Gas Liquids, Inc. and The Williams Companies, Inc. dated as of June 17, 2003 (filed as Exhibit 10.9 to Form 10-Q filed August 12, 2003).
	10.39*	—	Assumption Agreement dated June 17, 2003 by and between The Williams Companies, Inc. and WEG Acquisitions, L.P. (filed as Exhibit 10.10 to Form 10-Q filed August 12, 2003).
	10.40*	—	Agreement for the Release of Certain Indemnification Obligations dated as of May 26, 2004 by and among Magellan Midstream Holdings, L.P., Magellan G.P. LLC and Magellan Midstream Partners, L.P., on the one hand, and The Williams Companies, Inc., Williams Energy Services, LLC, Williams Natural Gas Liquids, Inc. and Williams GP LLC, on the other hand (filed as Exhibit 10.6 to Form 10-Q filed August 5, 2004).

180


Exhibit
No.			Description

	10.41*	—	Sale Agreement Relating to the Sale of the Interest of Williams Energy (Canada), Inc. in the Cochrane, Empress II and Empress V Straddle Plants dated as of July 8, 2004 between Williams Energy (Canada), Inc. and 1024234 Alberta Ltd. (filed as Exhibit 10.7 to Form 10-Q filed August 5, 2004).
	10.42*	—	Master Professional Services Agreement dated as of June 1, 2004, by and between The Williams Companies, Inc. and International Business Machines Corporation (filed as Exhibit 10.2 to Form 10-Q filed August 5, 2004).
	10.43*	—	Amendment No. 1 to the Master Professional Services Agreement dated June 1, 2004, by and between The Williams Companies, Inc. and International Business Machines Corporation made as of June 1, 2004 (filed as Exhibit 10.3 to Form 10-Q filed August 5, 2004).
	12	—	Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements.
	14*	—	Code of Ethics (filed as Exhibit 14 to Form 10-K for the fiscal year ended December 31, 2003).
	20*	—	Definitive Proxy Statement of Williams for 2005 (to be filed with the Securities and Exchange Commission on or before April 11, 2005).
	21	—	Subsidiaries of the registrant.
	23.1	—	Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.
	23.2	—	Consent of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc.
	23.3	—	Consent of Independent Petroleum Engineers and Geologists, Miller and Lents, LTD.
	24	—	Power of Attorney together with certified resolution.
	31.1	—	Certification of the Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2	—	Certification of the Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32	—	Certification of the Chief Executive Officer and the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*	Each such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.

(c) The financial statements of partially owned companies are not presented herein since none of them individually, or in the aggregate, constitute a significant subsidiary.

181

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	The Williams Companies, Inc.
	(Registrant)


	By:	/s/ Brian K. Shore



	Brian K. Shore
	Attorney-in-fact

Date: March 11, 2005

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date


/s/ Steven J. Malcolm Steven J. Malcolm	President, Chief Executive Officer and Chairman of the Board (Principal Executive Officer)	March 11, 2005

/s/ Donald R. Chappel* Donald R. Chappel	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	March 11, 2005

/s/ Gary R. Belitz* Gary R. Belitz	Controller (Principal Accounting Officer)	March 11, 2005

/s/ Hugh M. Chapman* Hugh M. Chapman	Director	March 11, 2005

/s/ William E. Green* William E. Green	Director	March 11, 2005

/s/ Juanita H. Hinshaw* Juanita H. Hinshaw	Director	March 11, 2005

/s/ W.R. Howell* W.R. Howell	Director	March 11, 2005

/s/ Charles M. Lillis* Charles M. Lillis	Director	March 11, 2005

/s/ George A. Lorch* George A. Lorch	Director	March 11, 2005

/s/ William G. Lowrie* William G. Lowrie	Director	March 11, 2005

/s/ Frank T. MacInnis* Frank T. MacInnis	Director	March 11, 2005

182


Signature		Title	Date


/s/ Janice D. Stoney* Janice D. Stoney		Director	March 11, 2005

/s/ Joseph H. Williams* Joseph H. Williams		Director	March 11, 2005

*By:	/s/ Brian K. Shore Brian K. Shore Attorney-in-fact		March 11, 2005

183

INDEX TO EXHIBITS


Exhibit
No.			Description

	3.1	—	Restated Certificate of Incorporation, as supplemented.
	3.2*	—	Restated By-laws (filed as Exhibit 3.1 to Form 8-K filed September 21, 2004 ).
	4.1*	—	Form of Senior Debt Indenture between Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4.1 to Form S-3 filed September 8, 1997).
	4.2*	—	Form of Floating Rate Senior Note (filed as Exhibit 4.3 to Form S-3 filed September 8, 1997).
	4.3*	—	Form of Fixed Rate Senior Note (filed as Exhibit 4.4 to Form S-3 filed September 8, 1997).
	4.4*	—	Fourth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed as Exhibit 4(j) to Form 10-K for the fiscal year ended December 31, 2000).
	4.5*	—	Fifth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed as Exhibit 4(k) to Form 10-K for the fiscal year ended December 31, 2000).
	4.6*	—	Sixth Supplemental Indenture dated January 14, 2002, between Williams and Bank One Trust Company, National Association, as Trustee (filed as Exhibit 4.1 to Form 8-K filed January 23, 2002).
	4.7*	—	Seventh Supplemental Indenture dated March 19, 2002, between The Williams Companies, Inc. as Issuer and Bank One Trust Company, National Association, as Trustee (filed as Exhibit 4.1 to Form 10-Q filed May 9, 2002).
	4.8*	—	Eighth Supplemental Indenture dated as of June 3, 2002, between The Williams Companies, Inc., as Issuer and Bank One Trust Company, N.A., as Trustee (filed as Exhibit 4.8 to Form 10-K for the fiscal year ended December 31, 2003).
	4.9*	—	Ninth Supplemental Indenture dated June 10, 2003 between The Williams Companies, Inc. as Issuer and JPMorgan Chase Bank as Trustee (filed as Exhibit 4.1 to Form 10-Q filed August 12, 2003).
	4.10*	—	Tenth Supplemental Indenture dated as of August 17, 2004, with respect to the Indenture dated as of November 10, 1997 between The Williams Companies, Inc. and JPMorgan Chase Bank (as successor trustee to Bank One Trust Company, National Association (successor to the First National Bank of Chicago)) (filed as Exhibit 99.2 for Form 8-K filed August 17, 2004).
	4.11*	—	Form of Senior Debt Indenture between Williams Holdings of Delaware, Inc. and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Williams Holdings of Delaware, Inc.’s Form 10-Q filed October 18, 1995).
	4.12*	—	First Supplemental Indenture dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams and Citibank, N.A., as Trustee (filed as Exhibit 4(o) to Form 10-K for the fiscal year ended December 31, 1999).
	4.13*	—	Senior Indenture dated February 25, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4.4.1 to MAPCO Inc.’s Amendment No. 1 to Form S-3 dated February 25, 1997).
	4.14*	—	Supplemental Indenture No. 1 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(o) to MAPCO Inc.’s Form 10-K for the fiscal year ended December 31, 1997).
	4.15*	—	Supplemental Indenture No. 2 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(p) to MAPCO Inc.’s Form 10-K for the fiscal year ended December 31, 1997).
	4.16*	—	Supplemental Indenture No. 3 dated March 31, 1998, among MAPCO Inc., Williams Holdings of Delaware, Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(j) to Williams Holdings of Delaware, Inc.’s Form 10-K for the fiscal year ended December 31, 1998).


Exhibit
No.			Description

	4.17*	—	Supplemental Indenture No. 4 dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(q) to Form 10-K for the fiscal year ended December 31, 1999).
	4.18*	—	Revised Form of Indenture between Barrett Resources Corporation, as Issuer, and Bankers Trust Company, as Trustee, with respect to Senior Notes including specimen of 7.55% Senior Notes (filed as Exhibit 4.1 to Barrett Resources Corporation’s Amendment No. 2 to Registration Statement on Form S-3 filed February 10, 1997).
	4.19*	—	First Supplemental Indenture dated 2001, between Barrett Resources Corporation, as Issuer, and Bankers Trust Company, as Trustee (filed as Exhibit 4.3 to Form 10-Q filed November 13, 2001).
	4.20*	—	Second Supplemental Indenture dated as of August 2, 2001, among Barrett Resources Corporation, as Issuer, Resources Acquisition Corp., The Williams Companies, Inc. and Bankers Trust Company, as Trustee (filed as Exhibit 4.4 to Form 10-Q filed November 13, 2001).
	4.21*	—	Third Supplemental Indenture dated as of May 20, 2004 with respect to the Indenture dated as of February 1, 1997 between Barrett Resources Corporation (predecessor-in-interest to Williams Production RMT Company) and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee (filed as Exhibit 99.2 to Form 8-K filed May 20, 2004).
	4.22*	—	Form of Note (filed as Exhibit 4.2 and included in Exhibit 4.1 to Form 8-K filed January 23, 2002).
	4.23*	—	Purchase Contract Agreement dated January 14, 2002, between Williams and JPMorgan Chase Bank, as Purchase Contract Agent (filed as Exhibit 4.3 to Form 8-K filed January 23, 2002).
	4.24*	—	Form of Income PACS Certificate (filed as Exhibit 4.4 and included in Exhibit 4.3 to Form 8-K filed January 23, 2002).
	4.25*	—	Pledge Agreement dated January 14, 2002, among Williams, Bank, as Purchase Contract Agent (filed as Exhibit 4.5 to Form 8-K filed January 23, 2002).
	4.26*	—	Remarketing Agreement dated January 14, 2002, among Williams, JPMorgan Chase Bank, as Purchase Contract Agent, and Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Remarketing Agent (filed as Exhibit 4.6 to Form 8-K filed January 23, 2002).
	4.27*	—	Supplemental Remarketing Agreement dated as of November 4, 2004 by and among Williams, Merill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporation, as Remarketing Agent, and JPMorgan Chase Bank, as Purchase Contract Agent (filed as exhibit 99.1 to Form 8-K filed November 9, 2004).
	4.28*	—	Indenture dated March 4, 2003, between Northwest Pipeline Corporation and JP Morgan Chase Bank, as Trustee (filed as Exhibit 4.1 to Form 10-Q filed May 13, 2003.
	4.29*	—	Indenture dated as of May 28, 2003, by and between The Williams Companies, Inc. and JPMorgan Chase Bank, as Trustee for the issuance of the 5.50% Junior Subordinated Convertible Debentures due 2033 (filed as Exhibit 4.2 to Form 10-Q filed August 12, 2003).
	4.30*	—	Amended and Restated Rights Agreement dated September 21, 2004 by and between The Williams Companies, Inc. and EquiServe Trust Company, N.A., as Rights Agent (filed as Exhibit 4.1 to Form 8-K filed September 21, 2004.
	10.1*	—	The Williams Companies, Inc. Supplemental Retirement Plan effective as of January 1, 1988 (filed as Exhibit 10(iii)(c) to Form 10-K for the fiscal year ended December 31, 1987).
	10.2*	—	First Amendment to The Williams Companies, Inc. Supplemental Retirement Plan effective as of April 1, 1988 (filed as Exhibit 10.2 to Form 10-K for the fiscal year ended December 31, 2003).
	10.3	—	Second Amendment to The Williams Companies, Inc. Supplemental Retirement Plan effective as of January 1, 2002 and January 1, 2003.
	10.4*	—	The Williams Companies, Inc. 1988 Stock Option Plan for Non-Employee Directors (filed as Exhibit A to the Proxy Statement dated March 14, 1988).
	10.5*	—	The Williams Companies, Inc. 1990 Stock Plan (filed as Exhibit A to the Proxy Statement dated March 12, 1990).
	10.6*	—	The Williams Companies, Inc. Stock Plan for Non-Officer Employees (filed as Exhibit 10(iii)(g) to Form 10-K for the fiscal year ended December 31, 1995).


Exhibit
No.			Description

	10.7*	—	The Williams Companies, Inc. 1996 Stock Plan (filed as Exhibit A to the Proxy Statement dated March 27, 1996).
	10.8*	—	The Williams Companies, Inc. 1996 Stock Plan for Non-Employee Directors (filed as Exhibit B to the Proxy Statement dated March 27, 1996).
	10.9*	—	Indemnification Agreement effective as of August 1, 1986, among Williams, members of the Board of Directors and certain officers of Williams (filed as Exhibit 10(iii)(e) to Form 10-K for the year ended December 31, 1986).
	10.10*	—	The Williams International Stock Plan (filed as Exhibit 10(iii)(l) to Form 10-K for the fiscal year ended December 31, 1998).
	10.11*	—	Form of Stock Option Secured Promissory Note and Pledge Agreement among Williams and certain employees, officers and non-employee directors (filed as Exhibit 10(iii)(m) to Form 10-K for the fiscal year ended December 31, 1998).
	10.12	—	Form of 2004 Deferred Stock Agreement among Williams and certain employees and officers.
	10.13	—	Form of 2004 Performance-Based Deferred Stock Agreement among Williams and executive officers.
	10.14*	—	Form of Stock Option Agreement among Williams and certain employees and officers (filed as Exhibit 99.1 to Form 8-K filed March 2, 2005).
	10.15*	—	Form of 2005 Deferred Stock Agreement among Williams and certain employees and officers (filed as Exhibit 99.2 to Form 8-K filed March 2, 2005).
	10.16*	—	Form of 2005 Performance-Based Deferred Stock Agreement among Williams and executive officers.(filed as Exhibit 99.3 to Form 8-K filed March 2, 2005).
	10.17*	—	The Williams Companies, Inc. 2001 Stock Plan (filed as Exhibit 4.1 to Form S-8 filed August 1, 2001).
	10.18*	—	The Williams Companies, Inc. 2002 Incentive Plan as amended and restated effective as of January 23, 2004 (filed as Exhibit 10.1 to Form 10-Q filed on August 5, 2004).
	10.19*	—	Form of Change in Control Severance Agreement between the Company and certain executive officers (filed as Exhibit 10.12 to Form 10-Q filed November 14, 2002).
	10.20*	—	Settlement Agreement, by and among the Governor of the State of California and the several other parties named therein and The Williams Companies, Inc. and Williams Energy Marketing & Trading Company dated November 11, 2002 (filed as Exhibit 10.79 for Form 10-K for the fiscal year ended December 31, 2002).
	10.21*	—	U.S. $500,000,000 Term Loan Agreement among Williams Production Holdings LLC, Williams Production RMT Company, as Borrower, the Several Lenders from time to time parties thereto, Lehman Brothers Inc. and Banc of America Securities LLC as Joint Lead Arrangers, Citigroup USA, Inc. and JPMorgan Chase Bank, as Co-Syndication Agents, Bank of America, N.A., as Documentation Agent, and Lehman Commercial Paper Inc., as Administrative Agent dated as of May 30, 2003 (filed as Exhibit 10.1 to Form 10-Q filed August 12, 2003).
	10.22*	—	The First Amendment to the Term Loan Agreement dated February 25, 2004, between Williams Production Holdings, LLC, Williams Production RMT Company, as Borrower, the several financial institutions as lenders and Lehman Commercial Paper Inc., as Administrative Agent dated as of May 30, 2003 (filed as Exhibit 10.3 to Form 10-Q filed May 6, 2004).
	10.23*	—	Guarantee and Collateral Agreement made by Williams Production Holdings LLC, Williams Production RMT Company and certain of its Subsidiaries in favor of Lehman Commercial Paper Inc. as Administrative Agent dated as of May 30, 2003 (filed as Exhibit 10.2 to Form 10-Q filed August 12, 2003).
	10.24*	—	U.S. $800,000,000 Credit Agreement dated as of June 6, 2003, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, as Borrowers, Citibank, N.A., as Administrative Agent and Collateral Agent, Bank of America, N.A., as Syndication Agent, JPMorgan Chase Bank, as documentation Agreement, Citibank, N.A. and Bank of America, N.A. as Issuing Banks, the banks named therein as Banks and Citigroup Global Markets Inc. and Banc of America Securities LLC as Joint Lead Arrangers and Joint Book Runners (filed as Exhibit 10.3 to Form 10-Q filed August 12, 2003).


Exhibit
No.			Description

	10.25*	—	Security Agreement dated as of June 6, 2003, among The Williams Companies, Inc., as Grantor, Citibank, N.A., as Collateral Agent and Citibank, N.A. as Securities Intermediary (filed as Exhibit 10.4 to Form 10-Q filed August 12, 2003).
	10.26*	—	U.S. $1,000,000,000 Credit Agreement dated as of May 3, 2004, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipeline Corporation, as Borrowers, Citicorp USA, Inc., as Administrative Agent and Collateral Agent, Citibank, N.A. and Bank of America, N.A., as Issuing Banks, the banks named therein as Banks, Bank of America, N.A., as Syndication Agent, JPMorgan Chase Bank, The Bank of Nova Scotia, The Royal Bank of Scotland plc as Co-Documentation Agents, Citigroup Global Markets Inc. and Banc of America Securities LLC as Joint Lead Arrangers and Co-Book Runners (filed as Exhibit 10.4 to Form 10-Q filed May 6, 2004).
	10.27*	—	Letter of Credit Commitment Increase Agreement dated August 4, 2004, by and among The Williams Companies, Inc., Citicorp USA in its capacity as Agent under the Credit Agreement dated as of May 3, 2004 among the Borrower, Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, the Agent, the Collateral Agent, the Banks and Issuing Banks party thereto and Citibank, N.A. and Bank of America, N.A. (filed as Exhibit 10.1 to Form 10-Q filed November 4, 2004).
	10.28*	—	Revolving Credit Commitment Increase Agreement dated August 4, 2004, by and among The Williams Companies, Inc., Citicorp USA in its capacity as Agent under the Credit Agreement dated as of May 3, 2004 among the Borrower, Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, the Agent, the Collateral Agent and the Banks and Issuing Banks party thereto, the Issuing Banks and Citicorp USA, Inc. (filed as Exhibit 10.2 to Form 10-Q filed November 4, 2004).
	10.29	—	Amendment Agreement dated as of October 19, 2004 among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipeline Corporation, as Borrowers, the banks, financial institutions and other institutional lenders that are parties to the Credit Agreement dated as of May 3, 2004 among the Borrowers, the Banks, Citicorp USA, Inc., as agent and Citibank, N.A. and Bank of America, N.A., as issuers of letters of credit under the Credit Agreement, the Agent and the Issuing Banks.
	10.30*	—	Western Midstream Security Agreement dated as of May 3, 2004, among Williams Gas Processing Company, Williams Field Services Company, Williams Gas Processing — Wamsutter Company as Grantors, in favor of Citicorp USA, Inc. as Collateral Agents (filed as Exhibit 10.5 to Form 10-Q filed May 6, 2004).
	10.31*	—	Pledge Agreement dated as of May 3, 2004, by Williams Field Services Group, Inc. in favor of Citicorp USA, Inc. as Collateral Agent (filed as Exhibit 10.6 to Form 10-Q filed May 6, 2004).
	10.32*	—	Western Midstream Guaranty by Williams Gas Processing Company, Williams Field Services Company, Williams Gas Processing — Wamsutter Company as Guarantors in favor of Citicorp USA, Inc. as Collateral Agent (filed as Exhibit 10.7 for Form 10-Q filed May 6, 2004).
	10.33*	—	Pipeline Holdco Guaranty by Williams Gas Pipeline Company, LLC as Guarantor in favor of Citicorp USA, Inc. as Collateral Agent (filed as Exhibit 10.8 to Form 10-Q filed May 6, 2004).
	10.34*	—	Amended and Restated U.S. $400,000,000 Five Year Credit Agreement dated April 14, 2004 and amended January 20, 2005 among The Williams Companies, Inc., as Borrower, the Initial Lenders named herein, as Initial Lenders , the Initial Issuing Banks named herein, as Initial Issuing Banks and Citibank, N.A, as Agent (filed as Exhibit 10.1 to Form 8-K filed on January 26, 2005).
	10.35*	—	Amended and Restated U.S. $100,000,000 Five Year Credit Agreement dated April 26, 2004 and amended January 20, 2005 among The Williams Companies, Inc., as Borrower, the Initial Lenders named herein, as Initial Lenders , the Initial Issuing Banks named herein, as Initial Issuing Banks and Citibank, N.A, as Agent (filed as Exhibit 10.2 to Form 8-K filed on January 26, 2005).
	10.36*	—	U.S. $400,000,000 Five Year Credit Agreement dated January 20, 2005 among The Williams Companies, Inc., as Borrower, the Initial Lenders named herein, as Initial Lenders, the Initial Issuing Banks named herein, as Initial Issuing Banks and Citibank, N.A, as Agent (filed as Exhibit 10.3 to Form 8-K filed on January 26, 2005).


Exhibit
No.			Description

	10.37*	—	U.S. $100,000,000 Five Year Credit Agreement dated January 20, 2005 among The Williams Companies, Inc., as Borrower, the Initial Lenders named herein, as Initial Lenders , the Initial Issuing Banks named herein, as Initial Issuing Banks and Citibank, N.A, as Agent (filed as Exhibit 10.4 to Form 8-K filed on January 26, 2005).
	10.38*	—	New Omnibus Agreement among WEG Acquisitions, L.P., Williams Energy Services, LLC, Williams Natural Gas Liquids, Inc. and The Williams Companies, Inc. dated as of June 17, 2003 (filed as Exhibit 10.9 to Form 10-Q filed August 12, 2003).
	10.39*	—	Assumption Agreement dated June 17, 2003 by and between The Williams Companies, Inc. and WEG Acquisitions, L.P. (filed as Exhibit 10.10 to Form 10-Q filed August 12, 2003).
	10.40*	—	Agreement for the Release of Certain Indemnification Obligations dated as of May 26, 2004 by and among Magellan Midstream Holdings, L.P., Magellan G.P. LLC and Magellan Midstream Partners, L.P., on the one hand, and The Williams Companies, Inc., Williams Energy Services, LLC, Williams Natural Gas Liquids, Inc. and Williams GP LLC, on the other hand (filed as Exhibit 10.6 to Form 10-Q filed August 5, 2004).
	10.41*	—	Sale Agreement Relating to the Sale of the Interest of Williams Energy (Canada), Inc. in the Cochrane, Empress II and Empress V Straddle Plants dated as of July 8, 2004 between Williams Energy (Canada), Inc. and 1024234 Alberta Ltd. (filed as Exhibit 10.7 to Form 10-Q filed August 5, 2004).
	10.42*	—	Master Professional Services Agreement dated as of June 1, 2004, by and between The Williams Companies, Inc. and International Business Machines Corporation (filed as Exhibit 10.2 to Form 10-Q filed August 5, 2004).
	10.43*	—	Amendment No. 1 to the Master Professional Services Agreement dated June 1, 2004, by and between The Williams Companies, Inc. and International Business Machines Corporation made as of June 1, 2004 (filed as Exhibit 10.3 to Form 10-Q filed August 5, 2004).
	12	—	Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements.
	14*	—	Code of Ethics (filed as Exhibit 14 to Form 10-K for the fiscal year ended December 31, 2003).
	20*	—	Definitive Proxy Statement of Williams for 2005 (to be filed with the Securities and Exchange Commission on or before April 11, 2005).
	21	—	Subsidiaries of the registrant.
	23.1	—	Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.
	23.2	—	Consent of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc.
	23.3	—	Consent of Independent Petroleum Engineers and Geologists, Miller and Lents, LTD.
	24	—	Power of Attorney together with certified resolution.
	31.1	—	Certification of the Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2	—	Certification of the Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32	—	Certification of the Chief Executive Officer and the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*	Each such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.


		facilities were reduced significantly during the fourth-quarter as incidental damage to our customers’ facilities was being repaired.

	•	Gulf Liquids Reclassification to Continuing Operations — During fourth-quarter 2004, we reclassified the operations of Gulf Liquids to continuing operations within our Midstream segment in accordance with EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations,” (EITF 03-13). Under the provisions of EITF 03-13, Gulf Liquids no longer qualifies for reporting as discontinued operations based on management’s expectation that we will continue to have significant commercial activity with the disposed entity. All periods presented reflect this restatement.

	•	Gulf Liquids Insurance Arbitration Award — During fourth-quarter 2004, an arbitration panel awarded Gulf Liquids $93.6 million, plus interest of $9.6 million. Prior to this judgment, the insurer had disputed coverage of certain financial assurances provided to Gulf Liquids on multiple construction contracts.

	•	Compliance with FERC Order 2004 — Effective June 1, 2004, and due in part to our response to FERC Order 2004, management and decision-making control of certain regulated gas gathering assets was transferred from our Midstream segment to our Gas Pipeline segment. We also requested a waiver from the FERC regarding compliance with FERC Order 2004 for the operation of Discovery Gas Transmission and Black Marlin assets. In July 2004, the FERC granted a partial waiver allowing our Midstream segment to continue to manage these assets without subjecting Midstream to energy affiliate status under FERC Order 2004. In order to comply with the remaining provisions of the FERC order, we determined it was necessary to transfer management of our equity investment in the Aux Sable processing plant to our Power segment. This transfer was effective September 21, 2004. All periods presented reflect these classifications.


		standards. Historically our gathering system realizes net gains and losses, and therefore, we do not consider these gains to be recurring in nature.

	•	Depreciation expense was $10 million higher in large part due to additional investments in the West region.


		payment is included in Payments of long-term debt on the Consolidated Statement of Cash Flows. In July 2004, we received payment of approximately $104 million from the California Power Exchange which is reported in Changes in accounts and notes receivable on the Consolidated Statement of Cash Flows.

	•	In October, we completed the exchange of approximately 33.1 million FELINE PACS units for one share of our common stock plus $1.47 in cash for each unit resulting in the retirement of $827 million of debt.

	•	In November, we completed the purchase and retirement of approximately $200 million of the remaining notes in connection with our FELINE PACS remarketing. Approximately $73.1 million of the original $1.1 billion of notes remains outstanding and is due on February 16, 2007.