Exhibit 99.1

NYSE: WMB

Date: Feb. 23, 2005

Williams Reports Unaudited Fourth-Quarter and Full-Year 2004 Financial Results

•   Businesses Demonstrate Strong Performance

•   Businesses Generate Nearly $1.5 Billion in Net Cash From Operating Activities

•   Debt Reduced by $4 Billion

•   Guidance Provided Through 2007

Summary Financial Information

	2004										2003
	4Q						Full Year				4Q						Full Year
	millions			per share			millions		per share		millions			per share			millions			per share
Income (loss) from continuing operations	$	95.5		$	0.17		$	93.2	$	0.18	$	(73.3	)	$	(0.14	)	$	(57.5	)	$	(0.17	)
Income (loss) from discontinued operations		(22.1	)		(0.04	)		70.5		0.13		19.6			0.04			326.6			0.63
Net income (loss)		73.4			0.13			163.7		0.31		(53.7	)		(0.10	)		(492.2	)		(1.01	)
Recurring income (loss) from continuing operations*		68.0			0.12			261.5		0.49		57.5			0.11			(15.8	)		(0.03	)
Recurring income (loss) from continuing operations — after MTM adjustment*	$	51.0		$	0.09		$	190.0	$	0.35	$	22.0		$	0.04		$	(170.0	)	$	(0.33	)

*A schedule reconciling income (loss) from continuing operations to recurring income from continuing operations and mark-to-market adjustments is available on Williams’ web site at www.williams.com.

      TULSA, Okla. – Williams (NYSE:WMB) announced 2004 unaudited net income of $163.7 million, or 31 cents per share on a diluted basis, compared with a net loss of $492.2 million, or a loss of $1.01 per share, for 2003.

      Results for 2003 were reduced by an after-tax charge of $761.3 million, or $1.47 per share, primarily to reflect the cumulative effect of adopting the mandated accounting standard for contracts involved in energy trading and risk management activities.

      For fourth-quarter 2004, the company reported net income of $73.4 million, or 13 cents per share on a diluted basis, compared with a net loss of $53.7 million, or a loss of 10 cents per share, for fourth-quarter 2003.

      The company reported 2004 income from continuing operations of $93.2 million, or 18 cents per share on a diluted basis, compared with a loss of $57.5 million, or a loss of 17 cents per share, in 2003 on a restated basis.

      The improvement in continuing operations over last year reflects the benefit of higher operating results, particularly in Midstream, and lower levels of interest expense primarily reflecting reduced levels of debt. The improvement was partially offset by $282.1 million in pre-tax charges for costs associated with the early retirement of debt, compared with $66.8 million for similar charges in 2003. With regard to unrealized mark-to-market gains or losses from the Power business, 2004 included a pre-tax gain of $304 million vs. a pre-tax gain of $262 million in 2003.

      For fourth-quarter 2004, the company reported income from continuing operations of $95.5 million, or 17 cents per share on a diluted basis, compared with a loss of $73.3 million, or a loss of 14 cents per share, for fourth-quarter 2003 on a restated basis.

      Results for fourth-quarter 2004 include a $103 million pre-tax gain and related interest associated with an insurance arbitration award at Midstream, while the same period in 2003 includes impairment charges of $89.1 million at Power. With regard to unrealized mark-to-market gains or losses from the Power business, the 2004 quarter included a pre-tax gain of $23 million vs. a pre-tax gain of $85 million in the 2003 quarter.

      Income from discontinued operations for 2004 was $70.5 million, or 13 cents per share on a diluted basis, compared with income of $326.6 million, or 63 cents per share, for 2003 on a restated basis. Results for both periods largely reflect net gains from asset sales.

      For fourth-quarter 2004, the company reported a loss from discontinued operations of $22.1 million, or a loss of 4 cents per share on a diluted basis, compared with income of $19.6 million, or 4 cents per share, for fourth-quarter 2003 on a restated basis.

CEO Perspective

      “The successful execution of our business plan is producing benefits that we’ll realize for years to come,” said Steve Malcolm, chairman, president and chief executive officer.

      “Over the past year, we have rapidly increased our drilling and production, dramatically reduced our debt and nearly doubled our net cash provided by operating activities.

      “These kinds of drivers enabled us to reward our shareholders with a five-fold dividend increase in the fourth quarter.

      “Our financial discipline and our focus on natural gas have served us well and can take us even further. Williams is positioned for continued growth and value creation.”

Recurring Results

      Recurring income from continuing operations – which excludes items of income or loss that the company characterizes as unrepresentative of its ongoing operations – was $261.5 million, or 49 cents per share, for 2004. In 2003, recurring results from continuing operations reflected a loss of $15.8 million on a restated basis, or a loss of 3 cents per share.

      For fourth-quarter 2004, recurring income from continuing operations was $68.0 million, or 12 cents per

share, compared with recurring income of $57.5 million, or 11 cents per share, for fourth-quarter 2003 on a restated basis.

      A reconciliation of the company’s income from continuing operations – a generally accepted accounting principles measure – to its recurring results accompanies this news release.

Recurring Results Adjusted for Residual Effect of Mark-to-Market Accounting

      With the company’s September decision to retain the Power business, the unit qualified for and elected to apply hedge accounting on a prospective basis beginning Oct. 1, 2004, for certain qualifying derivative contracts. Not all of Power’s derivative contracts will qualify for hedge accounting.

      Prior to the adoption of hedge accounting, Power accounted for its derivatives portfolio, which includes economic hedges on underlying tolling and other structured non-derivative contracts, on a mark-to-market basis. As a result, changes in fair value of its derivative portfolio over this time period have been recognized in earnings.

      As a result of applying hedge accounting Oct. 1, Power’s future results associated with contracts in the derivative portfolio should be less volatile. However, the residual mark-to-market effects will negatively impact reported results in future periods, serving to increase the difference between reported results and cash flows for several years.

      The expected cash flows and economic value of Power’s portfolio are not affected by the accounting election.

      To provide an added level of disclosure and transparency, Williams is providing an analysis of recurring earnings adjusted for all of Power’s mark-to-market effects. This measure was first introduced in third-quarter 2004 results.

      Recurring income from continuing operations – after adjusting for the mark-to-market impact to reflect income as though mark-to-market accounting had never been applied to Power’s designated hedges and other derivatives – was $190 million, or 35 cents per share, for 2004. In 2003, recurring results from continuing operations reflected a loss of $170 million, or a loss of 33 cents per share, after adjusting for the impact of mark-to-market accounting.

      For fourth-quarter 2004, recurring income from continuing operations – after adjusting for the mark-to-market impact to reflect income as though mark-to-market accounting had never been applied to Power’s designated hedges and other derivatives – was $51 million, or 9 cents per share, compared with recurring income of $22 million, or 4 cents per share, for fourth-quarter 2003 after adjusting for the impact of mark-to-market accounting.

      A reconciliation of the company’s income from continuing operations on a recurring basis to its recurring results that have been adjusted for the impact of mark-to-market accounting accompanies this news release.

Cash and Debt: Company Ends 2004 with Available Liquidity of $1.8 Billion

      Williams reduced its debt by approximately $4 billion in 2004 through scheduled maturities, early debt retirements and exchanges.

      At Dec. 31, 2004, Williams’ total outstanding debt was approximately $8 billion. Of this amount, approximately $247 million matures in 2005, $119 million matures in 2006, and $396 million matures in 2007. Williams has already retired $200 million of the 2005 maturities.

      Williams had unrestricted cash and cash equivalents of approximately $930 million at year-end 2004. At Dec. 31, Williams also had $881 million in unused and available revolving credit facilities, which are used primarily for issuing letters of credit and for liquidity.

      Net cash provided by operating activities for 2004 was approximately $1.5 billion, including $16 million from discontinued operations. For 2003, net cash provided by operating activities was $770 million, including $182 million from discontinued operations on a restated basis.

Business Segment Performance

      Williams’ primary businesses – Exploration & Production, Midstream Gas & Liquids, Gas Pipeline and Power – reported combined segment profit of $1.45 billion in 2004. A year ago, these businesses reported consolidated segment profit of $1.29 billion on a restated basis.

      In the fourth quarter of 2004, the four major businesses reported combined segment profit of $419 million vs. $161.1 million for the same period in 2003 on a restated basis.

Exploration & Production: Production Volume Growth Continues

      Exploration & Production, which includes natural gas production and development in the U.S. Rocky Mountains, San Juan Basin and Midcontinent, and oil and gas development in South America, reported 2004 segment profit of $235.8 million.

      A year ago, the business reported segment profit of $401.4 million. The decrease in segment profit is due primarily to the absence of $95 million in gains on the sale of assets in 2003, $24 million in lower income on derivative instruments that did not qualify for hedge accounting, and a $15.4 million loss provision in 2004 regarding an ownership dispute on prior period production. The benefit of higher production volumes was more than offset by decreased net realized average prices from hedging activities and increased operating expenses.

      For the fourth quarter of 2004, Exploration & Production reported segment profit of $70.9 million vs. $50.1 million for the same period last year.

      Fourth-quarter 2004 results increased primarily from the benefit of higher production volumes and higher net realized average prices.

      Average daily production volumes have increased 25 percent since the fourth quarter of 2003. In the fourth quarter of 2004, average daily production from domestic and international interests was approximately 612 million

cubic feet of gas equivalent, compared with 491 million cubic feet of gas equivalent during the fourth quarter of 2003.

      In the fourth quarter of 2004, average daily production in the Piceance basin was 255 million cubic feet of gas equivalent. This was an increase of 5 percent vs. third-quarter average daily production of 242 million cubic feet of gas equivalent in the Piceance.

      Overall, Piceance production has increased 61 percent since the fourth quarter of 2003, when average daily production was 158 million cubic feet of gas equivalent. Williams considers the Piceance basin to be its cornerstone property for production growth.

      Earlier today, Williams announced year-end 2004 proved U.S. natural gas reserves of 3.0 trillion cubic feet equivalent, up 10.5 percent from year-end 2003. Including its international interests, Williams has total proved natural gas and oil reserves of 3.2 trillion cubic feet equivalent.

      Domestic reserve net additions of 451 billion cubic feet equivalent exceeded last year’s 408 billion cubic feet in net additions.

      In 2004, Williams had a drilling success rate of approximately 99 percent. The company drilled 1,395 gross wells, of which 1,384 were successful. In 2003, Williams also achieved a 99 percent success rate, drilling 900 gross wells, of which 891 were successful.

      Williams plans to invest $500 million to $575 million in capital spending in Exploration & Production in 2005; $525 million to $625 million in 2006; and $525 million to $675 million in 2007.

      These investments are focused on increasing production from the company’s large portfolio of undeveloped reserves and pursuing expansion opportunities in existing and new basins.

      For 2005, Williams expects $400 million to $475 million in segment profit from Exploration & Production.

Midstream Gas & Liquids: Strong Margins Drive Record Quarter

      Midstream, which provides gathering, processing, natural gas liquids fractionation and storage services, reported 2004 segment profit of $549.7 million.

      A year ago, Midstream reported segment profit of $197.3 million on a restated basis. The increase in segment profit for 2004 reflects the benefit of significantly higher natural gas liquids production volumes and margins, higher olefins fractionation margins, a $93.6 million gain from a fourth-quarter insurance arbitration award associated with Gulf Liquids and the absence of $108.7 million of impairment charges in 2003 related to these same assets.

      In the fourth quarter, Midstream reclassified Gulf Liquids results for current and prior periods to continuing operations after considering recently issued accounting guidance for the reporting of discontinued operations. Williams has previously announced its intention to divest Gulf Liquids.

      For the fourth quarter of 2004, Midstream reported segment profit of $235.7 million vs. a restated $63.8 million for the same period last year.

      The increase in fourth-quarter 2004 segment profit primarily is due to higher natural gas liquids and olefins production margins, as well as the $93.6 million gain on the insurance arbitration award.

      In 2004, Williams completed more than 500 well connections to the company’s natural gas gathering systems in Wyoming and New Mexico.

      Williams plans to invest $120 million to $140 million in capital spending in Midstream in 2005; $110 million to $130 million in 2006; and $100 million to $130 million in 2007.

      These investments are focused on attracting new volumes to the company’s assets and further expanding Midstream’s systems in existing basins.

      For 2005, Williams expects $350 million to $430 million in segment profit from Midstream Gas & Liquids. The projected decline vs. 2004 results reflects an assumption that 2005 natural gas liquids margins will not reach the record levels achieved in 2004.

Gas Pipeline: Unit Posts Best Quarter for all of 2003 and 2004

      Gas Pipeline, which provides natural gas transportation and storage services primarily in the Northwest and along the Eastern Seaboard, reported 2004 segment profit of $585.8 million.

      A year ago, Gas Pipeline reported segment profit of $555.5 million on a restated basis. The increase in 2004 segment profit reflects higher equity earnings from Williams’ investment in the Gulfstream system and the absence of a 2003 charge of $25.6 million to write-off certain capitalized software development costs.

      The benefit of increased revenues associated with expansion projects was offset by lower commodity and short-term firm revenues, increased maintenance expense and costs to comply with new pipeline safety requirements and a $9 million charge in 2004 to write-off previously capitalized costs associated with an idled segment of the Northwest Pipeline system.

      For the fourth-quarter of 2004, Gas Pipeline reported segment profit of $156.8 million vs. a restated $148.2 million for the same period last year. The increase reflects the benefit of expansion projects and higher equity earnings from the Gulfstream investment. The 2004 period represents the highest quarterly segment profit for Gas Pipeline in 2003 and 2004.

      In November, Williams completed a new natural gas pipeline lateral near Everett, Wash., on Northwest Pipeline. The new 9-mile segment, known as the Everett Delta project, provides an additional 113,000 dekatherms per day of natural gas to a customer.

      In December, the Transco system established a one-day throughput record of 8.73 million dekatherms. The previous high of 8.34 million dekatherms occurred in 2003.

      Williams also filed an application with the Federal Energy Regulatory Commission in the fourth quarter to construct a $333 million project in western Washington in 2006. This is designed to permanently replace most of the 360,000 dekatherms per day of capacity on the Northwest system that was idled in December 2003. Approximately 131,000 dekatherms per day of service were restored on a temporary basis during the second quarter of 2004.

      Williams plans to invest $370 million to $420 million in capital spending in Gas Pipeline in 2005; $475 million to $550 million in 2006; and $250 million to $325 million in 2007.

      These investments are focused on maintenance, regulatory compliance, the capacity replacement project on Northwest Pipeline, and incremental expansions in growing markets.

      For 2005, Williams expects to generate $545 million to $585 million in segment profit from Gas Pipeline.

Power: Keeps Producing Positive Cash Flow

      In September 2004, Williams announced its decision to continue operating the Power business and cease efforts to exit the business.

      Power is focused on realizing expected cash flows, managing forward commodity risk and providing functions that support Williams’ natural gas businesses.

      Power, which manages more than 7,700 megawatts of power through long-term contracts, reported 2004 segment profit of $76.7 million. This includes the benefit of $304 million in forward unrealized mark-to-market gains.

      A year ago, Power reported segment profit of $135.1 million on a restated basis, which included forward unrealized mark-to-market gains of $262 million, and approximately $208 million in gains on the sale of assets and contracts.

      The 2004 decrease in segment profit is due primarily to reduced realized gross margin in power and natural gas, largely reflecting lower sales volumes. Also contributing to the decrease was the absence of gains on the 2003 sale of assets and contracts, partially offset by higher unrealized mark-to-market gains and significantly lower selling, general and administrative costs associated with staff reductions. The absence of certain impairment charges and loss accruals totaling approximately $143 million recorded in 2003 further offset the decline.

      For the fourth quarter of 2004, Power reported a segment loss of $44.4 million vs. a segment loss of $101 million for the same period last year on a restated basis. The 2004 period includes forward unrealized mark-to-market gains of $23 million vs. gains of $85 million in 2003.

      In 2004, Power generated approximately $565 million in cash flow from operations, largely from reductions in working capital used for credit and collateralization requirements. The unit also benefited from positive cash flows from its power and natural gas commodity portfolios. In 2003, Power generated approximately $162 million in cash flow from operations.

      For 2005, Williams expects a segment loss of $150 million to $250 million from Power. The loss is due to the approximate $300 million negative residual effect of having recognized mark-to-market gains on certain Power derivatives contracts in 2003 and 2004. Prior to October 2004, the unit did not qualify for hedge accounting due to Williams’ previous intent to exit the business. On a basis adjusted for the residual impact of mark-to-market accounting, Power expects segment profit of $50 million to $150 million.

      Power expects cash flow from operations of $50 million to $150 million in 2005.

Other

      In the Other segment, the company reported a 2004 segment loss of $41.6 million. A year ago, Other reported a segment loss of $50.5 million.

      The segment losses for both 2004 and 2003 are largely the result of impairment charges and equity losses associated with an investment in a Texas pipeline project.

      For the fourth quarter of 2004, Other reported a segment loss of $21.0 million vs. a segment loss of $7.7 million for the same period last year.

      The increase in quarterly segment loss is primarily due to increased equity losses associated with the Texas pipeline project and an $11.8 million accrual for environmental remediation at the Augusta refinery site.

Guidance Through 2007

      In 2005, Williams expects consolidated segment profit of $1.05 billion to $1.35 billion; cash flow provided from operating activities of $1.3 billion to $1.6 billion; and recurring income from continuing operations of 31 cents to 56 cents per share.

      On a recurring basis adjusted for the impact of mark-to-market accounting, Williams expects earnings of 63 cents to 88 cents per share for 2005.

      In 2006, Williams expects consolidated segment profit of $1.2 billion to $1.5 billion and cash flow provided from operating activities of $1.45 billion to $1.75 billion.

      In 2007, Williams expects consolidated segment profit of approximately $1.4 billion to $1.8 billion and cash flow provided from operating activities of $1.6 billion to $1.9 billion.

      The company has an overall capital budget of $1.0 billion to $1.2 billion for 2005; $1.15 billion to $1.35 billion for 2006; and $900 million to $1.1 billion in 2007.

Today’s Analyst Call

      Williams’ management will discuss the company’s fourth-quarter and year-end 2004 financial results during an analyst presentation to be webcast live at 10 a.m. Eastern today.

      Participants are encouraged to access the presentation and corresponding slides via www.williams.com. A limited number of phone lines also will be available at (800) 811-7286. International callers should dial (913) 981-4902. Callers should dial in at least 10 minutes prior to the start time. The webcast replay – audio and slides – for the year-end presentation will be available at www.williams.com later today. Audio-only replays of the presentation will be available at approximately 3 p.m. Eastern today through midnight on March 1. To access the replay, dial (888) 203-1112. International callers should dial (719) 457-0820. The replay confirmation code is 404873.

Form 10-K Filing Schedule

      The company plans to file its Form 10-K with the Securities and Exchange Commission in March. The

document will be available on both the SEC and Williams’ websites. A financial highlights package that is immediately available accompanies this news release.

About Williams (NYSE:WMB)

Williams, through its subsidiaries, primarily finds, produces, gathers, processes and transports natural gas. The company also manages a wholesale power business. Williams’ operations are concentrated in the Pacific Northwest, Rocky Mountains, Gulf Coast, Southern California and Eastern Seaboard. More information is available at www.williams.com.

Contact:	Kelly Swan
	Williams (media relations)
	(918) 573-6932
	Travis Campbell
	Williams (investor relations)
	(918) 573-2944
	Richard George
	Williams (investor relations)
	(918) 573-3679
	Courtney Baugher
	Williams (investor relations)
	(918) 573-5768

# # #

Williams’ reports, filings, and other public announcements might contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Private Securities Litigation Reform Act of 1995. You typically can identify forward-looking statements by the use of forward-looking words, such as “anticipate,” believe,” “could,” “continue,” “estimate,” “expect,” “forecast,” “may,” “plan,” “potential,” “project,” “schedule,” “will,” and other similar words. These statements are based on our intentions, beliefs, and assumptions about future events and are subject to risks, uncertainties, and other factors. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, other factors could cause our actual results to differ materially from the results expressed or implied in any forward-looking statements. Those factors include, among others: changes in general economic conditions and changes in the industries in which Williams conducts business; changes in federal or state laws and regulations to which Williams is subject, including tax, environmental and employment laws and regulations; the cost and outcomes of legal and administrative claims proceedings, investigations, or inquiries; the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including our credit ratings and general economic conditions; the level of creditworthiness of counterparties to our transactions; the amount of collateral required to be posted from time to time in our transactions; the effect of changes in accounting policies; the ability to control costs; the ability of each business unit to successfully implement key systems, such as order entry systems and service delivery systems; the impact of future federal and state regulations of business activities, including allowed rates of return, the pace of deregulation in retail natural gas and electricity markets, and the resolution of other regulatory matters; changes in environmental and other laws and regulations to which Williams and its subsidiaries are subject or other external factors over which we have no control; changes in foreign economies, currencies, laws and regulations, and political climates, especially in Canada, Argentina, Brazil, and Venezuela, where Williams has direct investments; the timing and extent of changes in commodity prices, interest rates, and foreign currency exchange rates; the weather and other natural phenomena; the ability of Williams to develop or access expanded markets and product offerings as well as their ability to maintain existing markets; the ability of Williams and its subsidiaries to obtain governmental and regulatory approval of various expansion projects; future utilization of pipeline capacity, which can depend on energy prices, competition from other pipelines and alternative fuels, the general level of natural gas and petroleum product demand, decisions by customers not to renew expiring natural gas transportation contracts; the accuracy of estimated hydrocarbon reserves and seismic data; and global and domestic economic repercussions from terrorist activities and the government’s response to such terrorist activities. In light of these risks, uncertainties, and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time that we have described. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Reconciliation of Income (Loss) from Continuing Operations to Recurring Earnings
(UNAUDITED)

	2003															2004
(Dollars in millions, except for per-share amounts)	1st Qtr *			2nd Qtr *			3rd Qtr *			4th Qtr *			Year *			1st Qtr *		2nd Qtr*			3rd Qtr*		4th Qtr			Year
Income (loss) from continuing operations(1)		($52.2	)	$	50.0		$	18.0			($73.3	)		($57.5	)	$	0.0		($18.5	)	$	16.2	$	95.5		$	93.2
Preferred stock dividends		6.8			22.7			—			—			29.5			—		—			—		—			—
Income (loss) from continuing operations available to common stockholders		($59.0	)	$	27.3		$	18.0			($73.3	)		($87.0	)	$	0.0		($18.5	)	$	16.2	$	95.5		$	93.2
Income (loss) from continuing operations — diluted earnings per share		($0.12	)	$	0.05		$	0.03			($0.14	)		($0.17	)	$	—		($0.03	)	$	0.03	$	0.17		$	0.17
Nonrecurring items:
Power
Accelerated compensation expense associated with workforce reductions		11.8			—			—			—			11.8			—		—			—		—			—
Severance accrual		—			0.6			—			—			0.6			—		—			—		—			—
Impairment of investment in Aux Sable		—			8.5			5.6			—			14.1			—		—			—		—			—
Loss accrual for regulatory issues(2)		—			20.0			—			—			20.0			—		—			—		—			—
Prior period item correction(3)		(13.7	)		(93.1	)		(1.0	)		(9.0	)		(116.8	)		—		—			—		—			—
Gain on sale of Jackson EMC power contracts		—			(175.0	)		(13.0	)		—			(188.0	)		—		—			—		—			—
Gain on sale of crude contracts and pipeline		—			(7.1	)		—			—			(7.1	)		—		—			—		—			—
Gain on sale of eSpeed stock		—			—			(13.5	)		—			(13.5	)		—		—			—		—			—
Impairment of goodwill(2)		—			—			—			45.0			45.0			—		—			—		—			—
Hazelton impairment		—			—			—			44.1			44.1			—		—			—		—			—
California rate refund and other accrual adjustments(4)		—			—			—			33.3			33.3			—		—			—		—			—
Total Power nonrecurring items		(1.9	)		(246.1	)		(21.9	)		113.4			(156.5	)		—		—			—		—			—
Gas Pipeline
Write-off of Oneline information system project		—			25.5			—			0.1			25.6			—		—			—		—			—
Severance accrual		—			0.9			—			—			0.9			—		—								—
Write-off of previously-capitalized costs — idled segment of Northwest’s pipeline		—			—			—			—			—			—		9.0								9.0
Total Gas Pipeline nonrecurring items		—			26.4			—			0.1			26.5			—		9.0			—		—			9.0
Exploration & Production
Gain on sale of certain E&P properties		—			(91.5	)		—			—			(91.5	)		—		—			—		—			—
Loss provision related to an ownership dispute		—			—			—			—			—			—		11.3			—		4.1			15.4
Total Exploration & Production nonrecurring items		—			(91.5	)		—			—			(91.5	)		—		11.3			—		4.1			15.4
Midstream Gas & Liquids
La Maquina depreciable life adjustment		—			—			4.2			—			4.2			—		—			6.4		1.2			7.6
Gain on sale of Louisiana Olefins assets		—			—			—			—			—			—		—			—		(9.5	)		(9.5	)
Gain on sale of West Texas LPG Pipeline, L.P.		—			—			(11.0	)		—			(11.0	)		—		—			—		—			—
Gain on sale of wholesale propane		—			—			—			(16.2	)		(16.2	)		—		—			—		—			—
Gulf Liquids arbitration award (Winterthur)		—			—			—			—			—			—		—			—		(93.6	)		(93.6	)
Impairment of Discovery		—			—			—			—			—			—		—			—		16.9			16.9
Gulf Liquids impairment		—			92.6			(0.3	)		16.4			108.7			—		—			—		—			—
Devil’s Tower revenue correction		—			—			—			—			—			—		(16.5	)		16.5					—
Total Midstream Gas & Liquids nonrecurring items		—			92.6			(7.1	)		0.2			85.7			—		(16.5	)		22.9		(85.0	)		(78.6	)
Other
Impairment of Longhorn and Aspen project(5)		—			49.6			—			—			49.6			—		10.8			—		—			10.8
Gain on sale of butane blending inventory		—			—			(9.2	)		—			(9.2	)		—		—								—
Augusta environmental reserve		—			—			—			—			—			—		—			—		11.8			11.8
Longhorn recapitalization fee		—			—			—			—			—			6.5		—			—		—			6.5
Total Other nonrecurring items		—			49.6			(9.2	)		—			40.4			6.5		10.8			—		11.8			29.1
Nonrecurring items included in segment profit (loss)		(1.9	)		(169.0	)		(38.2	)		113.7			(95.4	)		6.5		14.6			22.9		(69.1	)		(25.1	)
Nonrecurring items below segment profit (loss)
Convertible preferred stock dividends(2)(Preferred stock dividends — Corporate)		—			13.8			—			—			13.8			—		—			—		—			—
Impairment of cost-based investments(6) (Investing income (loss)-Various)		—			19.1			2.3			—			21.4			—		—			15.7		2.3			18.0
Severance accrual (General corporate expenses)		—			3.0			—			—			3.0			—		—			—		—			—
Impairment of Algar Telecom investment (Investing income (loss) — Other)		12.0			—			1.2			—			13.2			—		—			—		—			—
Write-off of capitalized debt expense (Interest accrued — Corporate)		—			14.5			—			—			14.5			—		3.8			—		—			3.8
Premiums, fees and expenses related to the debt repurchase and debt tender offer (Other income (expense) — net — Corporate and Exploration & Production)		—			—			—			66.8			66.8			—		96.7			155.1		29.7			281.5
Gulf Liquids arbitration award (Winterthur) — interest income — (Investing income loss) — Midstream)		—			—			—			—			—			—		—			—		(9.6	)		(9.6	)
Loss provision related to an ownership dispute — interest component (Interest accrued — Exploration & Production)		—			—			—			—			—			—		1.9			—		2.1			4.0
		12.0			50.4			3.5			66.8			132.7			—		102.4			170.8		24.5			297.7
Total nonrecurring items		10.1			(118.6	)		(34.7	)		180.5			37.3			6.5		117.0			193.7		(44.6	)		272.6
Tax effect for above items		3.9			(73.3	)		(14.2	)		49.7			(33.9	)		2.5		44.8			74.1		(17.1	)		104.3
Recurring income (loss) from continuing operations available to common stockholders		($52.8	)		($18.0	)		($2.5	)	$	57.5			($15.8	)	$	4.0	$	53.7		$	135.8	$	68.0		$	261.5
Recurring diluted earnings per common share		($0.10	)		($0.03	)	$	—		$	0.11			($0.03	)	$	0.01	$	0.10		$	0.26	$	0.12		$	0.49
Weighted-average shares — diluted (thousands)		517,652			524,546			524,711			518,502			518,137			519,485		521,698			529,525		586,497			535,611

(1)	Includes $126.8 million positive valuation adjustment associated with agreement to terminate contract with Allegheny in second quarter 2003.
(2)	No tax benefit.
(3)	Power recognized $116.8 million of revenue in 2003 from a correction of the accounting treatment previously applied to certain third party derivative contracts during 2002 and 2001.
(4)	For $5.6 million, no tax benefit.
(5)	For $20.2 million, no tax benefit in 2nd Qtr 2003.
(6)	For $21.4 million in 2003, no tax benefit.

* Amounts have been restated from 3rd Quarter 2004 to reflect Gulf Liquids as continuing operations.

Note: The sum of earnings (loss) per share for the quarters may not equal the total earnings (loss) per share for the year due to changes in the weighted-average number of common shares outstanding.

Adjustment to remove MTM impact

Dollars in millions except for per share amounts
	2004															2003
	1Q			2Q			3Q			4Q			Year			1Q			2Q			3Q			4Q			Year
Recurring income from cont. ops available to common shareholders	$	4		$	54		$	136		$	68		$	261		$	(53	)	$	(18	)	$	(2	)	$	58		$	(16	)
Recurring diluted earnings per common share	$	0.01		$	0.10		$	0.26		$	0.12		$	0.49		$	(0.10	)	$	(0.03	)	$	(0.00	)	$	0.11		$	(0.03	)
Mark-to-Market (MTM) adjustments:
Reverse forward unrealized MTM gains/losses		(24	)		(70	)		(188	)		(23	)		(304	)		1			(232	)		54			(85	)		(262	)
Add realized gains/losses from MTM previously recognized		136			11			45			(6	)		186			(17	)		45			(45	)		25			8
Total MTM adjustments		112			(59	)		(143	)		(29	)		(118	)		(15	)		(187	)		9			(60	)		(253	)
Tax effect of total MTM adjustments (at 39%)		44			(23	)		(56	)		(11	)		(46	)		(6	)		(73	)		4			(23	)		(99	)
After tax MTM adjustments		69			(36	)		(87	)		(17	)		(72	)		(9	)		(114	)		5			(37	)		(155	)
Recurring income from cont. ops available to common shareholders after MTM adjust.	$	73		$	18		$	49		$	51		$	190		$	(62	)	$	(132	)	$	3		$	22		$	(170	)
Recurring diluted earnings per share after MTM adj.	$	0.14		$	0.03		$	0.09		$	0.09		$	0.35		$	(0.12	)	$	(0.25	)	$	0.01		$	0.04		$	(0.33	)
weighted average shares — diluted (thousands)		519,485			521,698			529,525			586,497			535,611			517,652			524,546			524,711			518,502			518,137

Note: Recurring income from continuing operations available to common stockholders has been restated to reflect the reclassification of Gulf Liquids to continuing operations

Adjustments have been made to reverse estimated forward unrealized MTM gains/losses and add estimated realized gains/losses from MTM previously recognized, i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives.

Non-GAAP Utility Statement:

      This press release includes certain financial measures, EBITDA, free cash flow, recurring earnings and recurring segment profit, that are non-GAAP financial measures as defined under the rules of the Securities and Exchange Commission. EBITDA represents the sum of net income (loss), net interest expense, income taxes, depreciation and amortization of intangible assets, less income (loss) from discontinued operations. Recurring earnings and recurring segment profit provide investors meaningful insight into the Company’s results from ongoing operations. This press release is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Management uses these financial measures because they are widely accepted financial indicators used by investors to compare company performance. In addition, management believes that these measures provide investors an enhanced perspective of the operating performance of the Company’s assets and the cash that the business is generating. Neither EBITDA nor recurring earnings, free cash flow and recurring segment profit are intended to represent cash flows for the period, nor are they presented as an alternative to net income or cash flow from operations. They should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with United States generally accepted accounting principles.

      Certain financial information in this press release is also shown including Power mark-to-market adjustments. This press release is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Previously the Company did not qualify for hedge accounting with respect to its Power segment as a result of the Company’s stated intent to exit the Power business. The Company ceased efforts to market the sale of Power during the third quarter 2004, and now qualifies for hedge accounting. Hedge accounting reduces earnings volatility associated with Power’s portfolio of certain derivative hedging instruments. Prior to the adoption of hedge accounting, these derivative hedging instruments were accounted for on a mark-to-market basis with the change in fair value recognized in earnings each period. Management uses the mark-to-market adjustments to better reflect Power’s results on a basis that is more consistent with Power’s portfolio cash flows and to aid investor understanding. The adjustments reverse forward unrealized mark-to-market gains or losses from derivatives and add realized gains or losses from derivatives for which mark-to-market income has been previously recognized, with the effect that the resulting adjusted segment profit is presented as if mark-to-market accounting had never been applied to designated hedges or other derivatives. The measure is limited by the fact that it does not reflect potential unrealized future losses or gains on derivative contracts. However, management compensates for this limitation since reported earnings do reflect unrealized gains and losses of derivative contracts. Overall, management believes the mark-to-market adjustments provide an alternative measure that more closely matches realized cash flows for the Power segment.

Financial Highlights
(Unaudited)

	Three months ended						Years ended
	December 31,						December 31,
(Millions, except per-share amounts)	2004			2003*			2004		2003*
Revenues	$	2,964.2		$	3,513.5		$	12,461.3	$	16,651.0
Income (loss) from continuing operations	$	95.5		$	(73.3	)	$	93.2	$	(57.5	)
Income (loss) from discontinued operations	$	(22.1	)	$	19.6		$	70.5	$	326.6
Cumulative effect of change in accounting principles	$	—		$	—		$	—	$	(761.3	)
Net income (loss)	$	73.4		$	(53.7	)	$	163.7	$	(492.2	)
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	.17		$	(.14	)	$	.18	$	(.17	)
Income (loss) from discontinued operations	$	(.04	)	$	.04		$	.13	$	.63
Cumulative effect of change in accounting principles	$	—		$	—		$	—	$	(1.47	)
Net income (loss)	$	.13		$	(.10	)	$	.31	$	(1.01	)
Average shares (thousands)		552,272			518,502			529,188		518,137
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	.17		$	(.14	)	$	.18	$	(.17	)
Income (loss) from discontinued operations	$	(.04	)	$	.04		$	.13	$	.63
Cumulative effect of change in accounting principles	$	—		$	—		$	—	$	(1.47	)
Net income (loss)	$	.13		$	(.10	)	$	.31	$	(1.01	)
Average shares (thousands)		586,497			518,502			535,611		518,137
Shares outstanding at December 31 (thousands)								557,957		518,232

*Amounts have been restated or reclassified as described in Note 1 of Notes to Consolidated Statement of Operations.

Fourth Quarter 2004

Consolidated Statement of Operations
(Unaudited)

Revenues

Segment
costs and
expenses

Operating
income

Earnings (loss)
per share

	Three months ended						Years ended
	December 31,						December 31,
(Millions, except per-share amounts)	2004			2003*			2004			2003*
Power	$	2,038.6		$	2,585.4		$	9,272.4		$	13,195.5
Gas Pipeline		351.3			364.0			1,362.3			1,368.3
Exploration & Production		214.1			166.9			777.6			779.7
Midstream Gas & Liquids		867.1			709.7			2,882.6			2,784.8
Other		6.5			12.9			32.8			72.0
Intercompany eliminations		(513.4	)		(325.4	)		(1,866.4	)		(1,549.3	)
Total revenues		2,964.2			3,513.5			12,461.3			16,651.0
Costs and operating expenses		2,543.5			3,152.8			10,751.7			15,004.3
Selling, general and administrative expenses		97.8			92.7			355.5			421.3
Other (income) expense – net		(77.4	)		135.6			(51.6	)		(21.3	)
Total segment costs and expenses		2,563.9			3,381.1			11,055.6			15,404.3
General corporate expenses		35.3			24.5			119.8			87.0
Power		(50.8	)		(110.6	)		86.5			145.3
Gas Pipeline		148.0			142.2			557.6			539.6
Exploration & Production		67.7			48.3			223.9			392.5
Midstream Gas & Liquids		247.0			58.5			552.2			178.0
Other		(11.6	)		(6.0	)		(14.5	)		(8.7	)
General corporate expenses		(35.3	)		(24.5	)		(119.8	)		(87.0	)
Total operating income		365.0			107.9			1,285.9			1,159.7
Interest accrued		(171.5	)		(251.1	)		(834.4	)		(1,293.5	)
Interest capitalized		1.0			10.9			6.7			45.5
Interest rate swap income (loss)		.3			4.2			(5.0	)		(2.2	)
Investing income		16.8			29.5			48.0			73.2
Early debt retirement costs		(29.7	)		(66.8	)		(282.1	)		(66.8	)
Minority interest in income and preferred returns of consolidated subsidiaries		(5.4	)		(4.3	)		(21.4	)		(19.4	)
Other income – net		7.2			1.0			26.8			40.7
Income (loss) from continuing operations before income taxes and cumulative effect of change in accounting principles		183.7			(168.7	)		224.5			(62.8	)
Provision (benefit) for income taxes		88.2			(95.4	)		131.3			(5.3	)
Income (loss) from continuing operations		95.5			(73.3	)		93.2			(57.5	)
Income (loss) from discontinued operations		(22.1	)		19.6			70.5			326.6
Income (loss) before cumulative effect of change in accounting principles		73.4			(53.7	)		163.7			269.1
Cumulative effect of change in accounting principles		—			—			—			(761.3	)
Net income (loss)		73.4			(53.7	)		163.7			(492.2	)
Preferred stock dividends		—			—			—			29.5
Income (loss) applicable to common stock	$	73.4		$	(53.7	)	$	163.7		$	(521.7	)
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	.17		$	(.14	)	$	.18		$	(.17	)
Income (loss) from discontinued operations		(.04	)		.04			.13			.63
Income (loss) before cumulative effect of change in accounting principles		.13			(.10	)		.31			.46
Cumulative effect of change in accounting principles		—			—			—			(1.47	)
Net income (loss)	$	.13		$	(.10	)	$	.31		$	(1.01	)
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	.17		$	(.14	)	$	.18		$	(.17	)
Income (loss) from discontinued operations		(.04	)		.04			.13			.63
Income (loss) before cumulative effect of change in accounting principles		.13			(.10	)		.31			.46
Cumulative effect of change in accounting principles		—			—			—			(1.47	)
Net income (loss)	$	.13		$	(.10	)	$	.31		$	(1.01	)

*Certain amounts have been restated or reclassified as described in Note 1 of Notes to Consolidated Statement of Operations.

See accompanying notes.

Fourth Quarter 2004

Notes to Consolidated Statement of Operations
(Unaudited)

1.   Basis of presentation

Discontinued operations

      In accordance with the provisions related to discontinued operations within Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the results of operations for the following components have been reflected in the Consolidated Statement of Operations as discontinued operations (see Note 7):

•   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 Gas & Liquids (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 New River Project LLC (Gulf Liquids) to continuing operations within our Midstream segment in accordance with Emerging Issues Task Force (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 these reclassifications.

      Unless indicated otherwise, the information in the Notes to the Consolidated Statement of Operations relates to our continuing operations. Other components of our business may be classified as discontinued operations in the future as those operations are sold or classified as held-for-sale.

2.   Hedge accounting – power segment

      As a result of our past intent to exit the Power business, our Power segment 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 became eligible for hedge accounting under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” and elected hedge accounting beginning October 1, 2004, on a prospective basis 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 other comprehensive income in the equity section of the balance sheet, and then reclassified to earnings when the underlying hedged transactions (i.e. power sales and gas purchases) affect earnings.

3.   Segment revenues and profit (loss)

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. Equity earnings (losses) and income (loss) from investments are reported in investing income in the Consolidated Statement of Operations.

      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.

Fourth Quarter 2004

Notes to Consolidated Statement of Operations (continued)
(Unaudited)

3.   Segment revenues and profit (loss) (continued)

Reclassification of operations

      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.

Fourth Quarter 2004

Notes to Consolidated Statement of Operations (continued)
(Unaudited)

3.   Segment revenues and profit (loss) (continued)

						Exploration			Midstream
				Gas		&			Gas &
(Millions)	Power			Pipeline		Production			Liquids			Other			Eliminations			Total
Three months ended December 31, 2004
Segment revenues:
External	$	1,784.8		$	345.7	$	(27.7	)	$	859.2		$	2.2		$	—		$	2,964.2
Internal		256.7			5.6		241.8			7.9			4.3			(516.3	)		—
Total segment revenues		2,041.5			351.3		214.1			867.1			6.5			(516.3	)		2,964.2
Less intercompany interest rate swap income		2.9			—		—			—			—			(2.9	)		—
Total revenues	$	2,038.6		$	351.3	$	214.1		$	867.1		$	6.5		$	(513.4	)	$	2,964.2
Segment profit (loss)	$	(44.4	)	$	156.8	$	70.9		$	235.7		$	(21.0	)	$	—		$	398.0
Less:
Equity earnings (losses)		3.5			8.8		3.2			5.5			(9.3	)		—			11.7
Income (loss) from investments		—			—		—			(16.8	)		(.1	)		—			(16.9	)
Intercompany interest rate swap income		2.9			—		—			—			—			—			2.9
Segment operating income (loss)	$	(50.8	)	$	148.0	$	67.7		$	247.0		$	(11.6	)	$	—			400.3
General corporate expenses																			(35.3	)
Consolidated operating income																		$	365.0
Three months ended December 31, 2003
Segment revenues:
External	$	2,455.5		$	361.6	$	(8.8	)	$	702.1		$	3.1		$	—		$	3,513.5
Internal		139.6			2.4		175.7			7.6			9.8			(335.1	)		—
Total segment revenues		2,595.1			364.0		166.9			709.7			12.9			(335.1	)		3,513.5
Less intercompany interest rate swap income		9.7			—		—			—			—			(9.7	)		—
Total revenues	$	2,585.4		$	364.0	$	166.9		$	709.7		$	12.9		$	(325.4	)	$	3,513.5
Segment profit (loss)	$	(101.0	)	$	148.2	$	50.1		$	63.8		$	(7.7	)	$	—		$	153.4
Less:
Equity earnings (losses)		.4			6.0		1.8			1.0			(1.1	)		—			8.1
Income (loss) from investments		(.5	)		—		—			4.3			(.6	)		—			3.2
Intercompany interest rate swap income		9.7			—		—			—			—			—			9.7
Segment operating income (loss)	$	(110.6	)	$	142.2	$	48.3		$	58.5		$	(6.0	)	$	—			132.4
General corporate expenses																			(24.5	)
Consolidated operating income																		$	107.9

Fourth Quarter 2004

Notes to Consolidated Statement of Operations (continued)
(Unaudited)

3.   Segment revenues and profit (loss) (continued)

							Exploration			Midstream
				Gas			&			Gas &
(Millions)	Power			Pipeline			Production			Liquids			Other			Eliminations			Total
Year ended December 31, 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
Year ended December 31, 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	)		.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

Fourth Quarter 2004

Notes to Consolidated Statement of Operations (continued)
(Unaudited)

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 three months and the years ended December 31, 2004 and 2003, are as follows:

	(Income) Expense
	Three months ended						Years ended
	December 31,						December 31,
(millions)	2004			2003			2004			2003
Power
Gain on sale of Jackson power contract	$	—		$	—		$	—		$	(188.0	)
Impairment of goodwill		—			45.0			—			45.0
Impairment of generation facilities		—			44.1			—			44.1
Commodity Futures Trading Commission settlement		—			—			—			20.0
California rate refund and other accrual adjustments		—			19.5			—			19.5
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		—			.1			—			25.6
Exploration & Production
Loss provision related to an ownership dispute		4.1			—			15.4			—
Net gain on sale of certain natural gas properties		—			(.3	)		—			(96.7	)
Midstream Gas & Liquids
Gain on sale of the wholesale propane business		—			(16.2	)		—			(16.2	)
Impairment of Gulf Liquids assets		2.5			16.4			2.5			108.7
Arbitration award on a Gulf Liquids insurance claim dispute		(93.6	)		—			(93.6	)		—
Other
Gain on sale of blending assets		—			—			—			(9.2	)
Environmental accrual related to the Augusta refinery facility		11.8			—			11.8			—

Power

      Goodwill. During 2003, we were pursuing a strategy of exiting the Power business. Because of this 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 reporting unit. 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.

      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 rate refund and other accrual adjustments and relate to power marketing activities in California during 2000 and 2001.

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 March 31, 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.

      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 Winterthur 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.

Fourth Quarter 2004

Notes to Consolidated Statement of Operations (continued)
(Unaudited)

4.   Asset sales, impairments and other accruals (continued)

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 net remediation costs. Accruals may be adjusted as more information from the site investigation becomes available.

5.   Investing income

      Investing income for the three months and the years ended December 31, 2004 and 2003, is as follows:

	Three months ended						Years ended
	December 31,						December 31,
(millions)	2004			2003			2004			2003
Equity earnings*	$	11.7		$	8.1		$	49.9		$	20.3
Income (loss) from investments*		(16.9	)		3.2			(35.5	)		(25.3	)
Impairments of cost-based investments		(5.1	)		(.4	)		(28.5	)		(35.0	)
Interest income and other		27.1			18.6			62.1			113.2
Total	$	16.8		$	29.5		$	48.0		$	73.2

*Item also included in segment profit (see Note 3).

      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 Partners, Pipeline L.P. (Longhorn) primarily associated with the terms of a recapitalization plan, which is included in our Other segment;

•   $6.5 million net unreimbursed Longhorn recapitalization advisory fees, which is included in our Other segment; and

•   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.

      Impairments of cost-based investments for the years ended December 31, 2004 and 2003, primarily include impairments of certain international investments.

6.   Early debt retirement

      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.

7.   Discontinued operations

Summarized results of discontinued operations

      The following table presents the summarized results of discontinued operations for the three months and the years ended December 31, 2004 and 2003. Income (loss) from discontinued operations before income taxes for the years ended December 31, 2004 and 2003 includes charges of $152.7 million and $52.7 million, respectively, to increase our accrued liability associated with litigation concerning the Trans-Alaska Pipeline System Quality Bank. 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.

	Three months ended						Years ended
	December 31,						December 31,
(millions)	2004			2003			2004			2003
Revenues	$	—		$	289.3		$	353.4		$	2,614.6
Income (loss) from discontinued operations before income taxes	$	(.9	)	$	32.5		$	(121.3	)		197.5
(Impairments) and gain (loss) on sales — net		.6			(2.5	)		200.5			277.7
Provision for income taxes		(21.8	)		(10.4	)		(8.7	)		(148.6	)
Total income (loss) from discontinued operations	$	(22.1	)	$	19.6		$	70.5		$	326.6

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, including amounts paid to our subsidiaries for amounts previously due from the straddle plants. During third-quarter

Fourth Quarter 2004

Notes to Consolidated Statement of Operations (continued)
(Unaudited)

7.   Discontinued operations (continued)

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.

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 the 2003 impairment charge 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 the 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 cash. 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 the 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 impairments and the loss on 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 indemnifications we provided to 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. 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 approximately $59 million in cash. During 2003, we recognized a pre-tax loss on the sale of $5.4 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 by $195.7 million, including $23 million related to goodwill, to their estimated fair value less cost to sell at December 31, 2002. These operations were part of the previously reported Petroleum Services segment.

Fourth Quarter 2004

Notes to Consolidated Statement of Operations (continued)
(Unaudited)

7.   Discontinued operations (continued)

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. These assets were previously written 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 gain on the sale of an earn-out agreement we retained in the sale of the refinery. These 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 to sell at December 31, 2002, and did not recognize a significant gain or loss on the sale. These operations were part of the previously reported Petroleum Services segment.

8.   Cumulative effect of change in accounting principles

      On October 25, 2002, the EITF reached a consensus on Issue No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” This Issue rescinded EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” the impact of which is to preclude fair value accounting for energy trading contracts that are not derivatives pursuant to SFAS No. 133 and commodity trading inventories. The EITF also 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. The consensus is applicable for fiscal periods beginning after December 15, 2002, except for physical trading commodity inventories purchased after October 25, 2002, which may not be reported at fair value. We initially applied the consensus effective January 1, 2003, and reported the initial application as a cumulative effect of a change in accounting principle. The effect of initially applying the consensus reduced net income by approximately $762.5 million on an after tax basis. Physical trading commodity inventories at December 31, 2003, that were purchased prior to October 25, 2002, were reported at fair value at December 31, 2003, and included in the effect of initially applying the consensus. The change results primarily from power tolling load serving, transportation and storage contracts not meeting the definition of a derivative and no longer being reported at fair value. These contracts are now accounted for under an accrual model. Physical trading commodity inventories are stated at cost, not to be in excess of market.

9.   Recent accounting standards

In December 2004, the Financial Accounting Standards Board 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 currently intend to adopt the new statement as of the interim reporting period beginning July 1, 2005. Prior to adoption, we will continue to account for our stock-based compensation plans under Accounting Principles Board Opinion No. 25 and related guidance while applying the proforma disclosure requirements of SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of SFAS No. 123.”