Williams Companies, Inc

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 28, 2006

The Williams Companies, Inc.

(Exact name of registrant as specified in its charter)


Delaware	1-4174	73-0569878

(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification No.)


One Williams Center, Tulsa, Oklahoma		74172

(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: 918/573-2000

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:


o		Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)


o		Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240-14a-12)


o		Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))


o		Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

TABLE OF CONTENTS


Item 2.02. Results of Operations and Financial Condition
Item 7.01. Regulation FD Disclosure
Item 9.01. Financial Statements and Exhibits
INDEX TO EXHIBITS
Copy of Williams' Press Release
Copy of Williams' Slide Presentation
Copy of Williams' Press Release

Item 2.02. Results of Operations and Financial Condition.

On February 28, 2006, The Williams Companies, Inc. (“Williams” or the “Company”) issued a press release announcing its financial results for the quarter and year ended December 31, 2005. A copy of the press release and its accompanying financial highlights and reconciliation schedules are furnished as a part of this current report on Form 8-K as Exhibit 99.1 and is incorporated herein in its entirety by reference.

The press release and accompanying financial highlights and reconciliation schedules are being furnished pursuant to Item 2.02, Results of Operations and Financial Condition. The information furnished is not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, is not subject to the liabilities of that section and is not deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

Item 7.01. Regulation FD Disclosure.

Williams wishes to disclose for Regulation FD purposes its slide presentation, furnished herewith as Exhibit 99.2, to be utilized during a public conference call and webcast on the morning of February 28, 2006.

On February 28, 2006, Williams also announced that its domestic and international proved natural gas reserves as of December 31, 2005, increased to 3.6 trillion cubic feet equivalent. Williams replaced its 2005 U.S. natural gas production of 224 billion cubic feet equivalent at a ratio of 277 percent. A copy of the press release announcing the same is furnished as Exhibit 99.3 to this Current Report on Form 8-K and is incorporated herein.

The slide presentation and press release are being furnished pursuant to Item 7.01, Regulation FD Disclosure. The information furnished is not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, is not subject to the liabilities of that section and is not deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

Item 9.01. Financial Statements and Exhibits.

	(a)		None

	(b)		None

	(c)		Exhibits


		Exhibit 99.1		Copy of Williams’ press release dated February 28, 2006, publicly announcing its fourth quarter and year-end 2005 financial results.

		Exhibit 99.2		Copy of Williams’ slide presentation to be utilized during the


				February 28, 2006, public conference call and webcast.

		Exhibit 99.3		Copy of Williams’ press release dated February 28, 2006, publicly announcing its replacement of 2005 U.S. natural gas production.

Pursuant to the requirements of the Securities Exchange Act of 1934, Williams has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


	THE WILLIAMS COMPANIES, INC.

Date: February 28, 2006		/s/ Donald R. Chappel
	Name:	Donald R. Chappel
	Title:	Senior Vice President and Chief
		Financial Officer

INDEX TO EXHIBITS


EXHIBIT
NUMBER		DESCRIPTION
Exhibit 99.1		Copy of Williams’ press release dated February 28, 2006, publicly announcing its fourth quarter and year-end 2005 financial results.

Exhibit 99.2		Copy of Williams’ slide presentation to be utilized during the February 28, 2006, public conference call and webcast.

Exhibit 99.3		Copy of Williams’ press release dated February 28, 2006, publicly announcing its replacement of 2005 U.S. natural gas production.

exv99w1

Exhibit 99.1




NYSE: WMB

Date: Feb. 28, 2006

Williams Reports Fourth-Quarter and Full-Year 2005 Financial Results

•		U.S. Natural Gas Production Climbs 18% During 2005

•		Businesses Generate $1.45 Billion in Net Cash from Operating Activities for 2005

•		4Q Results Reduced by Litigation Accruals and Investment Impairments

•		Company Plans to Double Drilling Activity in Piceance Highlands in 2006

•		Company Provides Guidance Through 2008

Year-End Summary Financial Information


	2005					2004
Per share amounts are reported on a fully diluted basis	millions			per share		millions			per share
Income from continuing operations	$	317.4		$	0.53	$	93.2		$	0.18

Income (loss) from discontinued operations	($	2.1	)		–	$	70.5		$	0.13

Cumulative effect of change in accounting principle	($	1.7	)		–		–			–


Net income	$	313.6		$	0.53	$	163.7		$	0.31


Recurring income from continuing operations*	$	427.8		$	0.72	$	261.5		$	0.49

After-tax mark-to-market adjustments	$	85.0		$	0.14	($	72.0	)	($	0.14	)

Recurring income from continuing operations — after mark-to-market adjustment*	$	512.8		$	0.86	$	189.5		$	0.35


*		A schedule reconciling income (loss) from continuing operations to recurring income (loss) from continuing operations and mark-to-market adjustments (non-GAAP measures) is available on Williams’ Web site at www.williams.com and as an attachment to this press release.

Quarterly Summary Information


	4Q 2005						4Q 2004
Per share amounts are reported on a fully diluted basis	millions			per share			millions			per share
Income from continuing operations	$	68.8		$	0.11		$	95.5		$	0.17

Income (loss) from discontinued operations	($	0.3	)		–		($	22.1	)	($	0.04	)

Cumulative effect of change in accounting principle	($	1.7	)		–			–			–

Net income	$	66.8		$	0.11		$	73.4		$	0.13


Recurring income from continuing operations*	$	168.1		$	0.28		$	68.0		$	0.12

After-tax mark-to-market adjustments	($	13.8	)	($	0.02	)	($	17.0	)	($	0.03	)


Recurring income from continuing operations — after mark-to-market adjustment*	$	154.3		$	0.26		$	51.0		$	0.09

TULSA, Okla. – Williams (NYSE:WMB) announced 2005 unaudited net income of $313.6 million, or 53 cents per share on a diluted basis, compared with net income of $163.7 million, or 31 cents per share on a diluted basis, for 2004.

Results for 2005 reflect the benefit of increased natural gas production and higher net realized average prices for production sold, along with reduced levels of interest expense. Results for 2004 included $282.1 million in costs associated with the early retirement of debt.

Results for 2005 also include unrealized mark-to-market gains of $172 million from the Power business, compared with $304 million in 2004.

For fourth-quarter 2005, the company reported net income of $66.8 million, or 11 cents per share on a diluted basis, compared with net income of $73.4 million, or 13 cents per share on a diluted basis, for fourth-quarter 2004.

Results for fourth-quarter 2005 include $64 million in litigation accruals to resolve legacy issues associated with gas reporting and $61 million of impairment charges associated with two non-core equity investments.

The company reported 2005 income from continuing operations of $317.4 million, or 53 cents per share on a diluted basis, compared with $93.2 million, or 18 cents per share on a diluted basis, in 2004.

For fourth-quarter 2005, the company reported income from continuing operations of $68.8 million, or 11 cents per share on a diluted basis, compared with $95.5 million, or 17 cents per share on a diluted basis, for fourth-quarter 2004.

CEO Perspective

“Our growth is creating real economic value,” said Steve Malcolm, chairman, president and chief executive officer. “The investments we’re making in our businesses are generating significant results for shareholders and adding energy supplies and delivery reliability to the domestic market.

“In 2005, we more than doubled our performance on a key financial measure – our recurring earnings exclusive of the effect of mark-to-market accounting.

“We took critical steps last year to increase the pace of proving up natural gas reserves and increasing production in the United States. Our efforts paid off with significant increases in both production and reserves through drilling activity.

“This year, we are deploying still more drilling rigs. These rigs are designed to drill more efficiently and effectively. And we are continuing to expand our drilling horizon within the Piceance Basin of the Western Rockies, doubling the number of wells we drill in the comparatively undeveloped Highlands, where we drilled 25 wells last year. We clearly expect these continued efforts to yield proportional growth in financial performance in 2006 and beyond,” Malcolm said.

“Williams is rich with opportunity that spans the natural gas value chain from domestic reserves and production growth to midstream infrastructure development and pipeline capacity growth to meet demand on the Eastern Seaboard, Florida and the Northwest.

“We are projecting a growth horizon that will push our 2008 consolidated recurring segment profit to more than $2 billion on a basis adjusted for the effect of mark-to-market accounting,” he said.

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

To provide an added level of disclosure and transparency, Williams continues to provide an analysis of recurring earnings adjusted to remove all mark-to-market effects from its Power business unit. Recurring earnings exclude items of income or loss that the company characterizes as unrepresentative of its ongoing operations.

Recurring income from continuing operations – after adjusting for the mark-to-market effect to reflect income as though mark-to-market accounting had never been applied to Power’s designated hedges and other derivatives – was $512.8 million, or 86 cents per share, for 2005. In 2004, the adjusted recurring income from continuing operations was $189.5 million, or 35 cents per share.

For the fourth quarter of 2005, recurring income from continuing operations – after adjusting for the mark-to-market effect – was $154.3 million, or 26 cents per share, compared with $51 million, or 9 cents per share, for the same period in 2004.

A reconciliation of the company’s income from continuing operations to recurring income from continuing operations and mark-to-market adjustments accompanies this news release.

Business Segment Performance

Williams’ primary businesses – Exploration & Production, Midstream Gas & Liquids, Gas Pipeline and Power – reported combined segment profit of $1.39 billion in 2005. A year ago, these businesses reported combined segment profit of $1.45 billion.

Results for 2005 were reduced by lower levels of forward unrealized mark-to-market gains and litigation accruals associated with agreements to resolve gas reporting issues. This year’s results benefited from increased natural gas production volumes and higher net realized average prices.

In the fourth quarter of 2005, the four major businesses reported combined segment profit of $342.2 million, compared with $419 million for the same period last year. The fourth quarter of 2004 included a $93.6 million gain from an insurance arbitration award.

Exploration & Production: U.S. Volumes Up 18 Percent in 2005 from Drilling Activities

Exploration & Production, which includes natural gas production and development in the U.S. Rocky Mountains, San Juan Basin and Mid-Continent, and oil and gas development in South America, reported 2005 segment profit of $587.2 million.

A year ago, the business reported segment profit of $235.8 million. The improvement in 2005 reflects the

benefit of significant increases in both production volumes and net realized average prices for production sold.

In addition, average sales prices in 2005 reflect a lower share of hedged volumes and increased contracted prices on hedged volumes, along with approximately $30 million in net gains on the sale of non-operated properties.

The benefit of higher volumes and prices in 2005 was only partially offset by higher operating expenses.

For 2005, average daily production from domestic and international interests was approximately 662 million cubic feet of gas equivalent (MMcfe), compared with 564 MMcfe for the same period in 2004 – an increase of approximately 17 percent.

Production solely from domestic interests increased 18 percent to approximately 612 MMcfe in 2005 from 519 MMcfe in 2004.

For the fourth quarter of 2005, Exploration & Production reported segment profit of $206.4 million, compared with $70.9 million for the same period last year.

During the fourth quarter of 2005, Williams realized net domestic average prices of $5.66 per thousand cubic feet of gas equivalent (Mcfe), compared with $3.16 per Mcfe in the fourth quarter a year ago – an increase of 79 percent. Hedging activities limited the extent of the company’s ability to capture a higher benefit from market prices.

The improvement in the 2005 quarter also reflects an increase in production volumes. Average daily production from domestic volumes totaled 646 MMcfe during the fourth quarter of 2005. Increased production continues to primarily reflect higher volumes in the Piceance Basin.

In a separate announcement today, Williams reported year-end 2005 proved U.S. natural gas reserves of 3.4 trillion cubic feet equivalent, up 13.3 percent from year-end 2004 reserves. Including its international interests, Williams had total proved natural gas and oil reserves of 3.6 trillion cubic feet equivalent at year-end 2005.

Domestic additions and revisions of 603 billion cubic feet equivalent exceeded last year’s 451 billion cubic feet in additions and revisions – an increase of approximately 34 percent. Over the past three years, Williams has successfully transferred more than 1.4 trillion cubic feet of domestic reserves from probable to proved.

In 2005, Williams had a drilling success rate of approximately 99 percent. The company drilled 1,629 gross wells, of which 1,617 were successful. In 2004, Williams also achieved a 99 percent success rate, drilling 1,395 gross wells.

Williams currently has 19 rigs operating in the Piceance Basin of western Colorado – the company’s cornerstone for production and reserves growth.

Williams is deploying a new generation of drilling rig from Helmerich & Payne that is specifically designed for conditions in the Piceance Basin. Williams received two of the new rigs in the first quarter of 2006. Eight more rigs are scheduled for delivery at a pace of one per month during the year.

Williams plans to invest $950 million to $1.05 billion of capital in Exploration & Production in 2006. These investments are primarily focused on increasing domestic production by 15 to 20 percent during the year.

For 2006, Williams expects $650 million to $725 million in segment profit from Exploration & Production.

Midstream Gas & Liquids: Posts Strong Results, Despite Hurricanes and Lower Margins

Midstream, which provides natural gas gathering and processing services, along with natural gas liquids (NGL) fractionation and storage services and olefins production, reported 2005 segment profit of $471.2 million, compared with $549.7 million in 2004.

For the fourth quarter of 2005, Midstream reported segment profit of $112.4 million, compared with $235.7 million for the same period in 2004.

Results for 2004 were favorably affected by a fourth-quarter gain of $93.6 million related to an insurance arbitration award.

Results for 2005 benefited from $20.6 million in higher domestic gathering and processing fee-based revenues than a year ago, primarily a result of higher gathering fees and deepwater production handling payments.

These benefits were offset partially by a decrease in net NGL margins as volumes associated with natural gas processing facilities were affected by hurricane-related production shut-ins, power outages and intermittent periods of NGL rejection in the fourth quarter.

In 2005, Midstream sold 1.27 billion gallons of NGL equity volumes, compared with equity sales of 1.43 billion gallons in 2004. Third and fourth quarter performance in 2005 was negatively affected by hurricanes Katrina and Rita, as well as intermittent periods of unfavorable NGL recovery economics in the fourth quarter of 2005. These equity volumes are retained and subsequently marketed by Williams as payment-in-kind under the terms of certain processing contracts.

Gathering volumes increased slightly year-over-year despite the effects of the hurricanes during the third quarter. Gathering volumes were 1,253.3 trillion British thermal units (TBtu) in 2005, compared with 1,251.9 TBtu in 2004. As a result of the hurricanes, fee processing volumes declined year-over-year. In 2005, fee processing volumes were 721.4 TBtu, compared with 767.7 TBtu in 2004.

During the fourth quarter of 2005, Williams began receipt of new volumes of oil and gas from the Triton and Goldfinger fields at its Devils Tower deepwater spar in the eastern Gulf of Mexico. Also, Williams agreed to expand two of its deepwater pipelines in the same area to transport oil and gas production from the Blind Faith acreage beginning in 2008.

Effective Jan. 1, 2006, Williams acquired full ownership of the fourth cryogenic processing train at its Opal, Wyo., facility for approximately $32.5 million. Under a previous agreement, Williams shared the revenue stream from that unit. Williams now owns the entire Opal complex and is in the process of adding a fifth cryogenic processing train, scheduled for completion in second-quarter 2007.

Earlier this month, the company’s Cameron Meadows natural gas processing plant returned to service at partial capacity. This facility in Louisiana’s Cameron Parish had been offline since Hurricane Rita struck on Sept. 24. Williams expects to return the plant to full service in the second quarter this year.

Williams plans to invest $280 million to $300 million of capital in Midstream in 2006. These investments are primarily focused on expanding Midstream’s gathering and processing systems in the western United States and in the deepwater Gulf of Mexico.

For 2006, Williams expects $400 million to $500 million in segment profit from Midstream.

Gas Pipeline: Assesses Customer Demand for Possible Expansions

Gas Pipeline, which primarily delivers natural gas to markets along the Eastern Seaboard, in Florida and in the Northwest, reported 2005 segment profit of $585.8 million, comparable to the same level of segment profit a year ago.

Compared with 2004, segment profit in 2005 reflects higher equity earnings of approximately $14 million from Gulfstream and a $14.2 million favorable adjustment from the resolution of litigation associated with fuel-tracker filings. Those benefits were partially offset by approximately $24 million in lower transportation revenues, mainly from the termination a firm transportation agreement related to the Grays Harbor lateral on the Northwest system.

Additionally, 2005 includes prior-period income of $17.1 million associated with corrections to 2003-2004 pension obligations and $17.7 million associated with reversal of prior-period accruals, offset by a prior-period charge of approximately $27.5 million related to accounting and valuation corrections for certain inventory items, and an accrual of approximately $9.8 million for contingent refund obligations.

For the fourth quarter of 2005, Gas Pipeline reported segment profit of $92.8 million compared with $156.8 million for the same period in 2004. The decrease is primarily because of the previously mentioned prior-period charge of $27.5 million for certain inventory items and the $9.8 million contingent loss accrual.

The decrease in fourth-quarter 2005 also reflects the termination of the Grays Harbor contract, effective January 2005, combined with higher labor and benefits costs as well as the write-off of certain previously capitalized system costs.

During the fourth quarter and already in 2006, Williams has announced a variety of potential projects for expansions on all of its major interstate gas pipeline holdings – Transco, Northwest and Gulfstream Natural Gas System L.L.C., a joint venture in which Williams owns a 50 percent interest.

These non-binding open seasons are a preliminary, necessary step in soliciting customer interest for potential service expansions.

As an example, Williams concluded an open season for the proposed Sentinel project during the fourth quarter. As proposed, the Transco project was designed to provide an additional 200,000 to 300,000 dekatherms of natural gas deliverability per day in the Northeast. Williams ultimately received requests for a total of 256,000 dekatherms per day of capacity – well within the scope of the original plan.

Williams is evaluating the facility requirements to support the Transco Sentinel capacity and is in the process of negotiating shipper agreements with the parties that expressed interest. Service could be available as early as November 2008, subject to Federal Energy Regulatory Commission approval.

In December – following the successful completion of a prior open season in the summer of 2004 and a subsequent customer contract in spring 2005 – Transco filed an application with FERC to construct the Leidy to Long Island expansion in 2007. It will add 100,000 dekatherms of capacity, along with a compressor station, at an approximate cost of $121 million. Most of that expenditure is planned for 2007.

Also in the fourth quarter, Williams completed construction of a $16 million project to add 105,000

dekatherms per day of firm service on its Transco system in central New Jersey. This expansion was placed into service Nov. 1.

Williams plans to invest $710 million to $785 million of capital in Gas Pipeline in 2006. These investments are predominantly tied to maintenance, a capacity replacement project on Northwest Pipeline in Washington and expansions.

For 2006, Williams expects $475 million to $520 million in segment profit from Gas Pipeline. The projected decline compared with 2005 results is in part because of a new accounting rule that requires certain pipeline assessment costs that have historically been capitalized to be recorded as expense beginning in 2006, and higher interest expense at Gulfstream as a result of a debt offering in October 2005.

Power: Generates Positive Cash Flow in 2005; Continues to Reduce Forward Risk

Power manages a portfolio of more than 7,000 megawatts and provides services that support Williams’ natural gas businesses.

2005 Power Recurring Segment Profit Adjusted for Mark-to-Market Impact


	2005			2004
	(millions)			(millions)
Segment profit (loss)	($	256.7	)	$	76.7

Non-recurring adjustments	$	116.6			–


Recurring Segment profit (loss)	($	140.1	)	$	76.7

Mark-to-market adjustments — net	$	137.7		($	118.0	)


Recurring segment loss after mark-to-market adjustments	($	2.4	)	($	41.3	)

4Q Power Recurring Segment Profit Adjusted for Mark-to-Market Impact


	4Q ’05			4Q ’04
	(millions)			(millions)
Segment profit (loss)	($	69.4	)	($	44.4	)

Non-recurring adjustments	$	91.7			–


Recurring Segment profit (loss)	$	22.3		($	44.4	)

Mark-to-market adjustments — net	($	22.4	)	($	29.1	)


Recurring segment loss after mark-to-market adjustments	($	0.1	)	($	73.5	)

Power reported a 2005 segment loss of $256.7 million, compared with a segment profit of $76.7 million in 2004. Reported results include the effect of forward unrealized mark-to-market gains and losses.

The reduction is primarily the result of lower unrealized mark-to-market gains, lower tolling margins because of the effect of milder weather in California, and the effect of hurricanes on liquidity in the market. Results for 2005 also were reduced by significant litigation accruals and the impairment of a non-core equity investment.

Power reported a recurring segment loss adjusted for the effect of mark-to-market accounting of $2.4

million in 2005, compared with a loss of $41.3 million in 2004.

The year-over-year improvement on the adjusted basis primarily reflects the absence of losses from the interest rate and crude and refined products portfolios and lower selling, general and administrative expenses. That improvement was partially offset by lower margins from tolling and other accrual contracts in 2005.

Power reported a fourth quarter 2005 segment loss of $69.4 million, compared with a segment loss of $44.4 million in fourth-quarter 2004. Reported results include the effect of forward unrealized mark-to-market results.

The increased loss in the fourth quarter of 2005 is primarily the result of litigation accruals associated with resolving gas reporting issues and the impairment of a non-core equity investment, partially offset by higher unrealized mark-to-market gains and higher accrual revenues.

For the fourth quarter of 2005, Power reported a recurring segment loss adjusted for the effect of mark-to-market accounting of $0.1 million, compared with a loss of $73.5 million in 2004.

The year-over-year improvement on the adjusted basis primarily reflects the absence of losses from the interest rate and legacy natural gas portfolios and lower selling, general and administrative expenses.

In 2005, Power generated approximately $188 million in cash flow from operations, largely the result of working capital changes, including the return of margin dollars. In 2004, Power generated approximately $565 million in cash flow from operations, reflecting a significant return of margin dollars resulting from new letter of credit facilities, and changes in working capital.

Power last year also completed 17 new power sales contracts that range in term and volume through 2010. These contracts effectively reduce risk, increase value and increase cash-flow certainty. Additionally, the contracts reduce the portfolio’s future exposures to fuel-price and weather volatility.

For 2006, Williams expects a segment loss of between $135 million to $235 million from Power, absent the effect of any future unrealized mark-to-market gains or losses. In regard to cash flow from operations, Williams expects $50 million to $150 million from Power in 2006, excluding changes in working capital and payment of accruals associated with gas reporting agreements.

On a basis adjusted for the effect of mark-to-market accounting, Williams expects Power to generate 2006 recurring segment profit of $50 million to $150 million.

Cash and Debt: Company Ends 2005 With Available Liquidity of $2.6 Billion

At the close of business on Dec. 31, 2005, Williams had total liquidity of more than $2.6 billion. This consisted of approximately $1.6 billion in unrestricted cash and cash equivalents, approximately $123 million in other liquid investments and $961 million in unused and available revolving credit facilities.

Net cash provided by operating activities in 2005 was approximately $1.45 billion, comparable with the 2004 level of $1.49 billion.

Williams reduced its debt by approximately $249 million in 2005 through scheduled payments, maturities and conversions.

At Dec. 31, 2005, Williams’ total outstanding debt was approximately $7.7 billion. Approximately $220 million of debt – via the form of 5.5 percent junior subordinated convertible debentures – was converted to common equity in January 2006.

As a result of significant debt reductions in prior years such as 2003 and 2004, Williams realized a $162.7 million decrease in interest expense in 2005 compared with the prior year. The company had interest expense of $671.7 million in 2005, compared with $834.4 million in 2004 – a decrease of 19 percent.

Guidance Through 2008

In 2006, Williams expects $1.52 billion to $1.86 billion in consolidated segment profit and earnings per share of 78 cents to $1.03, both on a recurring basis adjusted for the effect of mark-to-market accounting. The projected increase over 2005 is primarily the result of expected increases in natural gas production volumes and anticipated pricing for those volumes.

In 2007, Williams expects consolidated segment profit of $1.83 billion to $2.25 billion on a recurring basis adjusted for the impact of mark-to-market accounting. The projected increase over 2006 is primarily the result of anticipated increases in natural gas production volumes, successfully completing Gas Pipeline rate cases, and increases in natural gas liquids volumes.

In 2008, Williams expects consolidated segment profit of $2.02 billion to $2.58 billion on a recurring basis adjusted for the impact of mark-to-market accounting. The projected increase over 2007 is primarily the result of anticipated increases in natural gas production volumes, the completion of expansions in Gas Pipeline and increases in natural gas liquids volumes.

Guidance for consolidated segment profit includes results for the four primary businesses, as well as the Other segment, which includes certain equity investments.

The company’s overall capital budget is $1.95 billion to $2.15 billion for 2006; $1.6 billion to $1.8 billion for 2007; and $1.5 billion to $1.75 billion for 2008.

Today’s Analyst Call

Williams’ management will discuss the company’s 2005 financial results and outlook through 2008 during an analyst presentation to be webcast live beginning 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) 818-5264. International callers should dial (913) 981-4910. Callers should dial in at least 10 minutes prior to the start of the discussion.

Replays of the webcast will be available for two weeks at www.williams.com following the event.

Form 10-K

The company expects to file its Form 10-K with the Securities and Exchange Commission in early March. The document will be available on both the SEC and Williams websites.

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

		Sharna Reingold
		Williams (investor relations)
		(918) 573-2078

# # #

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.

In regard to the company’s reserves in Exploration & Production, the SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves. We have used certain terms in this news release, such as “probable” reserves and “possible” reserves and “new opportunities potential” reserves that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under the assumed economic conditions. Probable and possible reserves are estimates of potential reserves that are made using accepted geological and engineering analytical techniques, but which are estimated with reduced levels of certainty than for proved reserves. Possible reserve estimates are less certain than those for probable reserves. New opportunities potential is an estimate of reserves for new areas for which we do not have sufficient information to date to raise the reserves to either the probable category or the possible category. New opportunities potential estimates are even less certain that those for possible reserves. Reference to “total resource portfolio” include proved, probable and possible reserves as well as new opportunities potential. Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our website at www.williams.com.


*Financial Highlights* (Unaudited)


	Three months ended						Years ended
	December 31,						December 31,
(Millions, except per-share amounts)	2005			2004			2005			2004

Revenues	$	3,676.1		$	2,964.2		$	12,583.6		$	12,461.3
Income from continuing operations	$	68.8		$	95.5		$	317.4		$	93.2
Income (loss) from discontinued operations	$	(0.3	)	$	(22.1	)	$	(2.1	)	$	70.5
Cumulative effect of change in accounting principle	$	(1.7	)	$	—		$	(1.7	)	$	—
Net income applicable to common stock	$	66.8		$	73.4		$	313.6		$	163.7
Basic earnings (loss) per common share:
Income from continuing operations	$	.12		$	.17		$	.55		$	.18
Income (loss) from discontinued operations	$	—		$	(.04	)	$	—		$	.13
Cumulative effect of change in accounting principle	$	—		$	—		$	—		$	—
Net income	$	.12		$	.13		$	.55		$	.31
Average shares (thousands)		573,371			552,272			570,420			529,188
Diluted earnings (loss) per common share:
Income from continuing operations	$	.11		$	.17		$	.53		$	.18
Income (loss) from discontinued operations	$	—		$	(.04	)	$	—		$	.13
Cumulative effect of change in accounting principle	$	—		$	—		$	—		$	—
Net income	$	.11		$	.13		$	.53		$	.31
Average shares (thousands)		609,106			586,497			605,847			535,611
Shares outstanding at December 31 (thousands)								573,592			557,957

Fourth Quarter 2005


*Consolidated Statement of Operations* (Unaudited)


		Three months ended						Years ended
		December 31,						December 31,
	(Millions, except per-share amounts)	2005			2004			2005			2004

REVENUES	Power	$	2,786.7		$	2,038.6		$	9,093.9		$	9,272.4
	Gas Pipeline		374.7			351.3			1,412.8			1,362.3
	Exploration & Production		420.2			214.1			1,269.1			777.6
	Midstream Gas & Liquids		890.9			867.1			3,232.7			2,882.6
	Other		7.8			6.5			27.2			32.8
	Intercompany eliminations		(804.2	)		(513.4	)		(2,452.1	)		(1,866.4	)

	Total revenues		3,676.1			2,964.2			12,583.6			12,461.3

SEGMENT COSTS AND EXPENSES	Costs and operating expenses		3,162.9			2,543.5			10,871.0			10,751.7
	Selling, general and administrative expenses		98.6			97.8			325.4			355.5
	Other (income) expense – net		62.5			(77.4	)		61.2			(51.6	)

	Total segment costs and expenses		3,324.0			2,563.9			11,257.6			11,055.6

	General corporate expenses		48.6			35.3			154.9			119.8

OPERATING INCOME (LOSS)	Power		(46.5	)		(50.8	)		(236.8	)		86.5
	Gas Pipeline		85.5			148.0			542.2			557.6
	Exploration & Production		200.5			67.7			568.4			223.9
	Midstream Gas & Liquids		102.9			247.0			446.6			552.2
	Other		9.7			(11.6	)		5.6			(14.5	)
	General corporate expenses		(48.6	)		(35.3	)		(154.9	)		(119.8	)

	Total operating income		303.5			365.0			1,171.1			1,285.9

	Interest accrued		(176.4	)		(171.5	)		(671.7	)		(834.4	)
	Interest capitalized		2.9			1.0			7.2			6.7
	Investing income (loss)		(21.2	)		16.8			23.7			48.0
	Early debt retirement costs		(0.4	)		(29.7	)		(0.4	)		(282.1	)
	Minority interest in income of consolidated subsidiaries		(8.9	)		(5.4	)		(25.7	)		(21.4	)
	Other income – net		14.6			7.5			27.1			21.8

	Income from continuing operations before income taxes and cumulative effect of change in accounting principle		114.1			183.7			531.3			224.5
	Provision for income taxes		45.3			88.2			213.9			131.3

	Income from continuing operations		68.8			95.5			317.4			93.2
	Income (loss) from discontinued operations		(0.3	)		(22.1	)		(2.1	)		70.5

	Income before cumulative effect of change in accounting principle		68.5			73.4			315.3			163.7
	Cumulative effect of change in accounting principle		(1.7	)		—			(1.7	)		—

	Net income applicable to common stock	$	66.8		$	73.4		$	313.6		$	163.7

EARNINGS (LOSS) PER SHARE	Basic earnings (loss) per common share:
	Income from continuing operations	$	.12		$	.17		$	.55		$	.18
	Income (loss) from discontinued operations		—			(.04	)		—			.13

	Income before cumulative effect of change in accounting principle		.12			.13			.55			.31
	Cumulative effect of change in accounting principle		—			—			—			—

	Net income	$	.12		$	.13		$	.55		$	.31

	Diluted earnings (loss) per common share:
	Income from continuing operations	$	.11		$	.17		$	.53		$	.18
	Income (loss) from discontinued operations		—			(.04	)		—			.13

	Income before cumulative effect of change in accounting principle		.11			.13			.53			.31
	Cumulative effect of change in accounting principle		—			—			—			—

	Net income	$	.11		$	.13		$	.53		$	.31

See accompanying notes.

Fourth Quarter 2005


*Notes to Consolidated Statement of Operations* (Unaudited)

1. BASIS OF PRESENTATION

Discontinued operations

The following are presented as discontinued operations in our Consolidated Statement of Operations:

	•		Refining, retail and pipeline operations in Alaska, part of the previously reported Petroleum Services segment;

	•		Straddle plants in western Canada, previously part of the Midstream segment.

Unless indicated otherwise, the information in the Notes to Consolidated Statement of Operations relates to our continuing operations.

Cumulative effect of change in accounting principle

In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation 47, “Accounting for Conditional Asset Retirement Obligations – an interpretation of FASB Statement No. 143”. The Interpretation clarifies that the term “conditional asset retirement” as used in Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

We adopted the Interpretation on December 31, 2005, and as a result, we recorded a cumulative effect of change in accounting principle of $1.7 million (net of $1 million of taxes).

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 No. 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)

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.

We currently evaluate performance based on segment profit (loss) from operations, which includes segment revenues from external and internal customers, operating costs and expenses, depreciation, depletion and amortization, equity earnings (losses) and income (loss) from investments, including impairments related to investments accounted for under the equity method. Intersegment sales are generally accounted for at current market prices as if the sales were to unaffiliated third parties.

During 2004, Power was party to 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. We terminated all interest-rate derivatives in the fourth quarter of 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 the 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 2005


*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, 2005

Segment revenues:
External	$	2,510.1		$	365.6	$	(81.3	)	$	878.1		$	3.6		$	—		$	3,676.1
Internal		276.6			9.1		501.5			12.8			4.2			(804.2	)		—

Total segment revenues	$	2,786.7		$	374.7	$	420.2		$	890.9		$	7.8		$	(804.2	)	$	3,676.1


Segment profit (loss)	$	(69.4	)	$	92.8	$	206.4		$	112.4		$	(30.3	)	$	—		$	311.9
Less:
Equity earnings (losses)		0.1			7.3		5.9			9.2			(2.0	)		—			20.5
Income (loss) from investments		(23.0	)		—		—			0.3			(38.0	)		—			(60.7	)

Segment operating income (loss)	$	(46.5	)	$	85.5	$	200.5		$	102.9		$	9.7		$	—			352.1

General corporate expenses																			(48.6	)

Consolidated operating income																		$	303.5


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
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

Fourth Quarter 2005

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, 2005

Segment revenues:
External	$	8,192.5		$	1,395.0		$	(201.6	)	$	3,187.6		$	10.1		$	—		$	12,583.6
Internal		901.4			17.8			1,470.7			45.1			17.1			(2,452.1	)		—

Total segment revenues	$	9,093.9		$	1,412.8		$	1,269.1		$	3,232.7		$	27.2		$	(2,452.1	)	$	12,583.6


Segment profit (loss)	$	(256.7	)	$	585.8		$	587.2		$	471.2		$	(105.0	)	$	—		$	1,282.5
Less:
Equity earnings (losses)		3.1			43.6			18.8			23.6			(23.5	)		—			65.6
Income (loss) from investments		(23.0	)		—			—			1.0			(87.1	)		—			(109.1	)

Segment operating income (loss)	$	(236.8	)	$	542.2		$	568.4		$	446.6		$	5.6		$	—			1,326.0


General corporate expenses																				(154.9	)


Consolidated operating income																			$	1,171.1


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

Fourth Quarter 2005

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, 2005 and 2004, are as follows:


	(Income) Expense
	Three months ended						Years ended
	December 31,						December 31,
(millions)	2005			2004			2005			2004

Power
Accrual for litigation contingencies	$	68.7		$	—		$	82.2		$	—
Gas Pipeline
Write-off of previously-capitalized costs		—			—			—			9.0
Exploration & Production
Gain on sale of certain natural gas properties		—			—			(29.6	)		—
Loss provision related to an ownership dispute		—			4.1			—			15.4
Midstream Gas & Liquids
Impairment of Gulf Liquids assets		—			2.5			—			2.5
Arbitration award on a Gulf Liquids insurance claim dispute		—			(93.6	)		—			(93.6	)
Other
Environmental accrual related to the Augusta refinery facility		—			11.8			—			11.8
Gain on sale of land		(9.0	)		—			(9.0	)		—

Power

Accrual for litigation contingencies. This accrual for the year ended December 31, 2005, includes a $77.2 million charge for agreements reached to substantially resolve exposure related to the inaccurate reporting of natural gas prices and volumes to an industry publication in 2002.

Midstream Gas & Liquids

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.

Other

Environmental accrual related to the Augusta refinery facility. As a result of information obtained in the fourth quarter of 2004 related to the Augusta refinery site, we accrued additional expense for completion of certain remediation work and other reasonably estimated net remediation costs.

Additional items

Costs and operating expenses within our Gas Pipeline segment for the year ended December 31, 2005 includes:

	•		An adjustment to reduce costs by $12.1 million to correct the carrying value of certain liabilities recorded in prior periods;

	•		Income from a liability reversal of $14.2 million associated with a favorable ruling involving adjustments to estimated gas purchase costs for operations in prior periods;

	•		A prior period charge of approximately $27.5 million related to accounting and valuation corrections for certain inventory items;

	•		An accrual of approximately $9.8 million for contingent refund obligations.

Selling, general and administrative expenses within our Gas Pipeline segment for the year ended December 31, 2005, includes:

	•		An adjustment to reduce costs by $5.6 million to correct the carrying value of certain liabilities recorded in prior periods;

	•		A $17.1 million reduction in pension expense for the cumulative impact of a correction of an error attributable to 2003 and 2004.

General corporate expenses for the year ended December 31, 2005, includes $13.8 million of expense in our Other segment related to the settlement of certain insurance coverage issues with an insurer that had underwritten portions of the fiduciary insurance applicable to our Employee Retirement Income Security Act litigation settlement and the directors and officers insurance applicable to our pending securities litigation.

Fourth Quarter 2005

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

5. INVESTING INCOME (LOSS)

Investing income (loss) for the three months and the years ended December 31, 2005 and 2004, is as follows:


	Three months ended						Years ended
	December 31,						December 31,
(millions)	2005			2004			2005			2004

Equity earnings*	$	20.5		$	11.7		$	65.6		$	49.9
Loss from investments*		(60.7	)		(16.9	)		(109.1	)		(35.5	)
Impairments of cost-based investments		—			(5.1	)		(2.2	)		(28.5	)
Interest income and other		19.0			27.1			69.4			62.1

Total	$	(21.2	)	$	16.8		$	23.7		$	48.0


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

Loss from investments for the year ended December 31, 2005, includes:

	•		An $87.2 million additional impairment of our investment in Longhorn Partners Pipeline L.P. (Longhorn), which is included in our Other segment. Of the total impairment, $38.1 million relates to fourth quarter.

	•		A $23 million fourth-quarter additional impairment of our equity interest in Aux Sable Liquids Products, L.P., which is included in our Power segment.

Loss from investments for the year ended December 31, 2004, includes:

	•		A $10.8 million impairment of our Longhorn investment;

	•		$6.5 million net unreimbursed Longhorn recapitalization advisory fees;

	•		A $16.9 million fourth-quarter impairment of our equity investment in Discovery Producer Services LLC, which is included in our Midstream segment.

Impairments of cost-based investments for the years ended December 31, 2005 and 2004 primarily include impairments of certain international investments.

6. EARLY DEBT RETIREMENT

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

7. PROVISION FOR INCOME TAXES

We provide for income taxes using the asset and liability method as required by SFAS No. 109, “Accounting for Income Taxes.” During 2005, as a result of the reconciliation of our tax basis and book basis assets and liabilities, we recorded a $20.2 million tax benefit adjustment.

8. DISCONTINUED OPERATIONS

Income (loss) from discontinued operations in 2004 is composed of gains on the sales of the Canadian straddle plants and the Alaska refining, retail and pipeline operations of $189.8 million and $3.6 million, respectively, as well as $22 million in income from our Canadian straddles discontinued operation. Partially offsetting these are $153 million of charges to increase our accrued liability associated with certain Quality Bank litigation matters involving valuation methodologies for products transported on the Trans-Alaska Pipeline System.

9. RECENT ACCOUNTING STANDARDS

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, as issued by the FASB, was to be effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. However, in April 2005, the Securities and Exchange Commission adopted a new rule that delayed the effective date for revised SFAS No. 123 to the beginning of the fiscal year that begins after June 15, 2005. We intend to adopt the revised Statement on January 1, 2006.

On June 30, 2005, the Federal Energy Regulatory Commission issued an order, “Accounting for Pipeline Assessment Cost,” to be effective January 1, 2006. The order requires companies to expense certain assessment costs that we have historically capitalized. As a result of this order, we anticipate expensing approximately $27 million to $35 million in 2006 that previously would have been capitalized.

Fourth Quarter 2005

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

(UNAUDITED)


	2004													2005
(Dollars in millions, except 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 available to common stockholders	$	—		($18.5	)	$	16.2	$	95.5		$	93.2		$	202.2		$	40.7		$	5.7		$	68.8		$	317.4

Income (loss) from continuing operations — diluted earnings (loss) per common share	$	—		($0.03	)	$	0.03	$	0.17		$	0.17		$	0.34		$	0.07		$	0.01		$	0.11		$	0.53


Nonrecurring items:
Power
Accrual for a regulatory settlement ⁽¹⁾		—		—			—		—			—			4.6			—			—			—			4.6
Accrual for litigation contingencies ⁽¹⁾		—		—			—		—			—			—			13.1			0.4			68.7			82.2
Impairment of Aux Sable		—		—			—		—			—			—			—			—			23.0			23.0
Prior period correction		—		—			—		—			—			6.8			—			—			—			6.8
Total Power nonrecurring items		—		—			—		—			—			11.4			13.1			0.4			91.7			116.6

Gas Pipeline
Prior period liability corrections — TGPL		—		—			—		—			—			(13.1	)		(4.6	)		—			—			(17.7	)
Prior period pension adjustment — TGPL		—		—			—		—			—			—			(17.1	)		—			—			(17.1	)
Write-off of previously-capitalized costs — idled segment of Northwest’s pipeline		—		9.0			—		—			9.0			—			—			—			—			—
Income from favorable ruling on FERC appeal (1999 Fuel Tracker)		—		—			—		—			—			—			—			(14.2	)		—			(14.2	)
Prior period inventory corrections — TGPL		—		—			—		—			—			—			—			—			27.5			27.5
Accrual of contingent refund obligation — TGPL		—		—			—		—			—			—			—			—			9.8			9.8

Total Gas Pipeline nonrecurring items		—		9.0			—		—			9.0			(13.1	)		(21.7	)		(14.2	)		37.3			(11.7	)

Exploration & Production
Gain on sale of E&P properties		—		—			—		—			—			(7.9	)		—			(21.7	)		—			(29.6	)
Loss provision related to an ownership dispute		—		11.3			—		4.1			15.4			0.3			—			—			—			0.3

Total Exploration & Production nonrecurring items		—		11.3			—		4.1			15.4			(7.6	)		—			(21.7	)		—			(29.3	)

Midstream Gas & Liquids
La Maquina depreciable life adjustment		—		—			6.4		1.2			7.6			—			—			—			—			—
Gain on sale of Louisiana Olefins assets		—		—			—		(9.5	)		(9.5	)		—			—			—			—			—
Gulf Liquids arbitration award (Winterthur)		—		—			—		(93.6	)		(93.6	)		—			—			—			—			—
Impairment of Discovery		—		—			—		16.9			16.9			—			—			—			—			—
Devils Tower revenue correction		—		(16.5	)		16.5		—			—			—			—			—			—			—

Total Midstream Gas & Liquids nonrecurring items		—		(16.5	)		22.9		(85.0	)		(78.6	)		—			—			—			—			—

Other
Impairment of Longhorn		—		10.8			—		—			10.8			—			49.1			—			38.1			87.2
Write-off of capitalized project development costs		—		—			—		—			—			—			4.0			—			—			4.0
Augusta environmental reserve		—		—			—		11.8			11.8			—			—			—			—			—
Gain on sale of real property		—		—			—		—			—			—			—			—			(9.0	)		(9.0	)
Longhorn recapitalization fee		6.5		—			—		—			6.5			—			—			—			—			—

Total Other nonrecurring items		6.5		10.8			—		11.8			29.1			—			53.1			—			29.1			82.2


Nonrecurring items included in segment profit (loss)		6.5		14.6			22.9		(69.1	)		(25.1	)		(9.3	)		44.5			(35.5	)		158.1			157.8

Nonrecurring items below segment profit (loss)
Impairment of cost-based investments (Investing income (loss) -Various)		—		—			15.7		2.3			18.0			—			—			—			—			—
Write-off of capitalized debt expense (Interest accrued — Corporate)		—		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)		—		96.7			155.1		29.7			281.5			—			—			—			—			—
Gulf Liquids arbitration award (Winterthur) — interest income — (Investing income / loss) — Midstream)		—		—			—		(9.6	)		(9.6	)		—			—			—			—			—
Gain on sale of remaining interests in Seminole Pipeline and MAPL (Investing income / loss — Midstream)		—		—			—		—			—			—			(8.6	)		—			—			(8.6	)
Loss provision related to an ownership dispute — interest component (Interest accrued — Exploration & Production)		—		1.9			—		2.1			4.0			2.7			—			—			—			2.7
Directors and officers insurance policy adjustment (General corporate expenses — Corporate)		—		—			—		—			—			—			—			13.8			—			13.8
Loss provision related to ERISA litigation settlement (Other income (expense) — net - Corporate)		—		—			—		—			—			—			—			5.0			—			5.0
Legal fees associated with shareholder litigation (General corporate expenses — Corporate)		—		—			—		—			—			—			—			—			9.4			9.4

		—		102.4			170.8		24.5			297.7			2.7			(8.6	)		18.8			9.4			22.3

Total nonrecurring items		6.5		117.0			193.7		(44.6	)		272.6			(6.6	)		35.9			(16.7	)		167.5			180.1
Tax effect for above items ⁽¹⁾		2.5		44.8			74.1		(17.1	)		104.3			(2.8	)		10.7			(6.4	)		48.0			49.5
Adjustment for nonrecurring excess deferred tax benefit		—		—			—		—			—			—			—			—			(20.2	)		(20.2	)


Recurring income (loss) from continuing operations available to common stockholders	$	4.0	$	53.7		$	135.8	$	68.0		$	261.5		$	198.4		$	65.9		($	4.6	)	$	168.1		$	427.8


Recurring diluted earnings (loss) per common share	$	0.01	$	0.10		$	0.26	$	0.12		$	0.49		$	0.33		$	0.11		($	0.01	)	$	0.28		$	0.72


Weighted-average shares — diluted (thousands)		519,485		521,698			529,525		586,497			535,611			599,422			578,902			580,735			609,106			605,847


⁽¹⁾		No tax effect on $.6 million of the accrual for a regulatory settlement in 1st quarter 2005 and $8 million and $42 million of the accrual for litigation contingencies in 2nd quarter 2005 and 4th quarter 2005, respectively.

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.

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.

Adjustment to remove MTM impact

Dollars in millions except for per share amounts


	2005
	1Q			2Q			3Q			4Q			Year
Recurring income (loss) from cont. ops available to common shareholders	$	198		$	67		$	(5	)	$	168		$	428
Recurring diluted earnings per common share	$	0.33		$	0.11		$	(0.01	)	$	0.28		$	0.72

Mark-to-Market (MTM) adjustments:
Reverse forward unrealized MTM gains/losses		(221	)		(22	)		141			(70	)		(172	)
Add realized gains/losses from MTM previously recognized		113			77			72			48			310

Total MTM adjustments		(108	)		55			213			(22	)		138

Tax effect of total MTM adjustments		(42	)		21			83			(8	)		53


After tax MTM adjustments		(66	)		34			130			(14	)		85

Recurring income from cont. ops available to common shareholders after MTM adjust.	$	132		$	101		$	125		$	154		$	513
Recurring diluted earnings per share after MTM adj.	$	0.22		$	0.17		$	0.22		$	0.26		$	0.86

weighted average shares — diluted (thousands)		599,422			578,902			580,735			609,106			605,847


	2004
	1Q			2Q			3Q			4Q			Year
Recurring income from cont. ops available to common shareholders	$	4		$	54		$	136		$	68		$	261
Recurring diluted earnings per common share	$	0.01		$	0.10		$	0.26		$	0.12		$	0.49

Mark-to-Market (MTM) adjustments:
Reverse forward unrealized MTM gains/losses		(24	)		(70	)		(187	)		(23	)		(304	)
Add realized gains/losses from MTM previously recognized		136			11			45			(6	)		186

Total MTM adjustments		112			(59	)		(142	)		(29	)		(118	)

Tax effect of total MTM adjustments		44			(23	)		(55	)		(11	)		(46	)


After tax MTM adjustments		68			(36	)		(87	)		(17	)		(72	)

Recurring income from cont. ops available to common shareholders after MTM adjust.	$	72		$	18		$	49		$	51		$	190
Recurring diluted earnings per share after MTM adj.	$	0.14		$	0.03		$	0.09		$	0.09		$	0.35

weighted average shares — diluted (thousands)		519,485			521,698			529,525			586,497			535,611

exv99w2

Williams 2005 4th Quarter Earnings February 28, 2006 Exhibit 99.2

Our 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 the 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: Our businesses are subject to complex government regulations that are subject to changes in the regulations themselves or in their interpretation or implementation; Our ability 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; 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; The different regional power markets in which we compete or will compete in the future have changing regulatory structures; Our risk measurement and hedging activities might not prevent losses; 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; We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets; Our operating results might fluctuate on a seasonal and quarterly basis; Risks related to laws of other countries, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments; Legal proceedings and governmental investigations related to our business; Recent developments affecting the wholesale power and energy trading industry sector that have reduced market activity and liquidity; Because we no longer maintain investment grade credit ratings, our counterparties have required us to provide higher amounts of credit support; Despite our restructuring efforts, we may not attain investment grade ratings; Institutional knowledge represented by our former employees now employed by our outsourcing service provider might not be adequately preserved; Failure of the outsourcing relationship might negatively impact our ability to conduct our business; Our ability to receive services from outsourcing provider locations outside the United States might be impacted by cultural differences, political instability, or unanticipated regulatory requirements in jurisdictions outside the United States; We could be held liable for the environmental condition of any of our assets, which could include losses or costs of compliance that exceed our current expectations; Environmental regulation and liability relating to our business will be subject to environmental legislation in all jurisdictions in which it operates, and such legislation may be subject to change; Potential changes in accounting standards that might cause us to revise our financial disclosure in the future, which might change the way analysts measure our business or financial performance; The continued availability of natural gas reserves to our natural gas transmission and midstream businesses; Our drilling, production, gathering, processing and transporting activities involve numerous risks that might result in accidents and other operating risks and costs; Compliance with the Pipeline Improvement Act may result in unanticipated costs and consequences; 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; The threat of terrorist activities and the potential for continued military and other actions; The historic drilling success rate of our exploration and production business is no guarantee of future performance; and Our assets and operations can be affected by weather and other phenomena. 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. Forward Looking Statements

Oil & Gas Reserves Disclaimer The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves. We use certain terms in this presentation, such as "probable" reserves and "possible" reserves and "new opportunities potential" reserves that the SEC's guidelines strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under the assumed economic conditions. Probable and possible reserves are estimates of potential reserves that are made using accepted geological and engineering analytical techniques, but which are estimated with reduced levels of certainty than for proved reserves. Possible reserve estimates are less certain than those for probable reserves. New opportunities potential is an estimate of reserves for new areas for which we do not have sufficient information to date to raise the reserves to either the probable category or the possible category. New opportunities potential estimates are even less certain that those for possible reserves. Reference to "total resource portfolio" include proved, probable and possible reserves as well as new opportunities potential. Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our Web site at www.williams.com.

2005 Review Steve Malcolm Chairman, President & CEO

2005 Headlines Key earnings measure more than doubles Generated $1.45 billion net cash from operations Production increases dramatically Took steps to accelerate reserves development Successful launch of master limited partnership Significant progress in resolving legacy issues Overview

What you'll hear about 2005 E&P growing - production, reserves, profits Recurring results up 122% U.S. production up 18% -- mostly via drill bit 277% reserves replacement with >99% success rate Total proved reserves 3.6 Tcfe Piceance Highlands shows promise Midstream sustains '04 record high; gears up for more growth Strength in the face of two hurricanes Brings new deepwater volumes on line Commits to expand capacity in Rockies Gas Pipeline customer demand supports growth Growth strengthens competitive position Sets delivery record again Rate case preparation begins Power reduces risk Executes additional mid-term deals Generates positive cash flow Overview

What you'll hear about 2006 and beyond Overview Expect to grow key earnings measure over 3-year horizon Opportunity rich Significant reserves for development Sizable growth projects in gathering and processing Stable of expansions that strengthen gas pipelines' competitive position Demand growth in key areas should drive more hedging of power portfolio Investing in value growth Committed more than $5 billion in capital projects Weighting capital toward E&P Opportunities expected to add CapEx for Midstream Expect to increase segment profit nearly 50% by 2008 Continued improvement in debt-to-cap ratio

Financial Results and 2006 Outlook Don Chappel CFO

Financial Results Dollars in millions (except per share amounts) 4th Qtr Year 2005 2004 2005 2004 Income from Continuing Operations $69 $95 $318 $93 Income (Loss) from Discontinued Operations - (22) (2) 71 Cumulative effect of change in accounting principle (2) - (2) - Net Income $67 $73 $314 $164 Net Income/Share $0.11 $0.13 $0.53 $0.31 Recurring Income from Cont. Ops./Share $0.28 $0.12 $0.72 $0.49 Recurring Income from Continuing Operations After MTM Adjustments/Share $0.26 $0.09 $0.86 $0.35 Consolidated A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' website at www.williams.com and at the end of this presentation.

Recurring Income from Continuing Operations 4th Qtr Year 2005 2004 2005 2004 Income from Continuing Operations $69 $95 $318 $93 Nonrecurring Items Accrual for Regulatory & Litigation Contingencies/Settlements 78 - 96 - Impairments/Losses/Write-offs 61 31 119 70 Expense related to prior periods 28 4 - 15 Gain on Sale of Assets (9) (10) (47) (10) Debt Retirement Expense - 30 - 282 Insurance Arbitration Award - (103) - (103) Other - Net 9 4 12 18 Total nonrecurring 167 (44) 180 272 Tax Effect of Adjustments 48 (17) 50 104 Adjustment for nonrecurring excess deferred tax benefit (20) - (20) - Recurring Income from Continuing Operations Available to Common $168 $68 $428 $261 Recurring Income from Continuing Operations/Share $0.28 $0.12 $0.72 $0.49 Consolidated A more detailed schedule reconciling income from continuing operations to recurring income from continuing operations is available on Williams' website at www.williams.com and at the end of this presentation. Dollars in millions (except per share amounts)

4th Qtr Year 2005 2004 2005 2004 Recurring Income from Continuing Operations After Mark-to-Market Adjustments Note: Adjustments have been made to reverse estimated forward unrealized MTM gains (losses) and add estimated realized gains from MTM previously recognized, i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives. A more detailed schedule reconciling income from continuing operations to recurring income from continuing operations after MTM adjustments is available on Williams' website at www.williams.com. Dollars in millions( except per share amounts) Recurring Income from Continuing Ops. Available to Common $168 $68 $428 $261 Recurring Diluted Earnings per Common Share $0.28 $0.12 $0.72 $0.49 Mark-to-Market (MTM) adjustments for Power: Reverse forward unrealized MTM (gains) losses (70) (23) (172) (304) Add realized gains from MTM previously recognized 48 (6) 310 186 Total MTM adjustments (22) (29) 138 (118) Tax Effect of Total MTM Adjustments (8) (11) 53 (46) After-tax MTM Adjustments (14) (17) 85 (72) Recurring income from Continuing Operations Avail. To Common Shareholders After MTM Adjustments $154 $51 $513 $190 Recurring Diluted Earnings Per Share After MTM adjustments $0.26 $0.09 $0.86 $0.35 Consolidated

Liquidity at Year-End 2005 Consolidated Dollars in millions Cash and cash equivalents 1,597 $ Other current securities 123 Less: Subsidiary & international cash Customer margin deposits payable $ 240 321 (561) Available unrestricted cash 1,159 Available revolver capacity 961 Total Liquidity 2,120 $

Business Unit Results

Exploration & Production Ralph Hill Senior Vice President

Dollars in millions 4th Qtr Year 2005 2004 2005 2004 Segment Profit $206 $71 $587 $236 Nonrecurring: Ownership Issue - 4 - 15 Gain on sale of assets - - (29) - Recurring Segment Profit $206 $75 $558 $251 4Q04 to 4Q05 financial highlights include: Volume increase of 14% Domestic net realized price increase of 79% Recurring segment profit increase of 175% $173 million negative hedge impact in 4Q05, $359 million year to date Exploration & Production Segment Profit

Strong Domestic Production Growth of 18% Exploration & Production 2005 Domestic production grew 18% or 93 MMcfe/d over 2004 15 - 20% production growth projected for 2006

Exploration & Production 2005 Accomplishments and Current Update Impressive domestic volume growth of 18% Domestic reserves replacement of 277% Successfully recruited talent, increased staff 34% Big George production continues to climb 2 rigs operating in Barnett Shale Mature San Juan basin production increased 4% Record International profit fueled by 8% volume increase and crude price 19 rigs operating in Piceance as of February 2006 2nd H&P rig on site Piceance Highlands production reaches 18 MMcfe/d

Powder River - Big George Coal Area Up 74 MMcfe/d or 101% over a year ago Up 11 MMcfe/d or 9% sequentially Big George production is driving basin growth Exploration & Production Williams' Big George Gross Production 0 20 40 60 80 100 120 140 160 Jun '04 Sep '04 Dec '04 Mar '05 Jun '05 Sep '05 Dec '05 MMcfe/d

Piceance Production Growth Up 88 MMcfe/d or 34% over a year ago Up 17 MMcfe/d or 5% sequentially Exploration & Production Williams' Piceance Net Production 150 200 250 300 350 2Q '04 3Q '04 4Q '04 1Q '05 2Q '05 3Q '05 4Q '05 MMcfe/d

An Industry Leader in 2005 Cost Performance Lease operating expense of $0.36 / Mcfe 3-year average F&D cost of $0.92 / Mcfe G&A cost of $0.34 / Mcfe Exploration & Production

Strong 2005 Reserves Performance Exploration & Production Total proved reserves 3.6 Tcfe Domestic proved reserves up 13.3% to 3.4 Tcfe 277% domestic reserves replacement 99% success rate Moved 603 Bcfe to proved Transfers of Probable to Proved Reserves (Bcfe) 2003 2004 Total Total for retained basins 408 451 1,462 2005 603

Exploration & Production Domestic Proved Reserves Reconciliation - -224 - -11 +603 +23 - -191 +451 Prod. +28 Prod. Acq. Sold YE 2003 Adds/ Rev. Acq. Adds/ Rev. YE 2005 YE 2004

Project Area Net Acres Estimated Gross Potential Locations Estimated Net Potential Reserves (Bcfe) 2004 Wells 2005 Wells Projected 2006 Wells Trail Ridge (10-acre density) 21,112 1,500 1,500 - 2,000 3 12 20 Ryan Gulch (40-acre density) 16,078 800 700 3 5 15 Allen Point (40-acre density) 6,240 200 140 0 6 9 Red Point (10-acre density) 1,908 190 200 0 2 10 Total 45,338 2,690 2,540 - 3,040 6 25 54 Piceance Highlands Projects Summary Exploration & Production

Piceance Highlands - Results To Date Exploration & Production Project Area Wells Drilled Average 30 Day Rate / Completed Well (MMcfe/d) Expected EUR* Range (Bcfe/well) Trail Ridge 15 1.1 1.2 - 1.6 Ryan Gulch 8 1.2 1.2 - 2.0 Allen Point 6 1.1 1.2 - 1.6 Red Point 2 1.2 1.2 - 1.4 * Estimated Ultimate Recovery

New E&P Opportunities Piceance Basin: Shale Ridge Prospect (Dakota Sandstone play) Leased 13,904 gross/net acres 100% WI; 87.5% NRI 10-year lease term Piceance Basin: Pending Williams Fork Project 2006 drill-to-earn commitment 11,000 net acres Uinta Basin: Sterling Hollow Prospect (Mesaverde tight gas sands play) Leased 39,911 contiguous gross/net acres 100% WI; 87.5% NRI 10-year lease term Paradox Basin: Resource Play (Ismay Group shales and tight gas sandstones) Leased 30,608 gross/net acres 100% WI; 87.5% NRI 5-year and 10-year terms on leases Douglas Creek Arch Uncompahgre Uplift UTAH ARIZONA COLORADO NEW MEXICO Piceance Basin Uinta Basin Paradox Basin WYOMING Exploration & Production

Williams is a Leader in US Gas Production Growth through the Drill Bit Exploration & Production (1) US production given on a natural gas equivalent basis, natural gas only production not available. Source: Publicly reported data from EvaluateEnergy.com, press releases, and company websites

Reflective of core basins $5.75 is after hedging and includes average basin market price of $6.75 before hedging Cash costs include LOE, G&A, taxes and gathering F&D costs include acquisition and development expenditures/proved reserves ('03-'05 average) Cash Margin Analysis Exploration & Production 3-Year Average (2006-08) $0.81 Previous $0.92 Previous $5.52 $5.75 Cash Margin Cash Costs Previous $1.81 $3.71 $1.77 $3.98 $0.00 $1.25 $2.50 $3.75 $5.00 Realized Gas Price Assumption Margin/Cost Assumption F&D Costs

2006 2007 2008 Segment profit $650 - 725 $775 - 900 $950 - 1,100 Annual DD&A 335 - 375 425 - 475 475 - 525 Segment profit + DD&A $985 - 1,100 $1,200 - 1,375 $1,425 - 1,625 Capital spending $950 - 1,050 $950 - 1,050 $1,000 - 1,150 Production (MMcfe/d) 750 - 825 875 - 975 950 - 1,100 Unhedged Price Assumption, ($/Mcf) NYMEX $8.50 $7.00 $7.00 Average San Juan/Rockies Price $7.32 $6.09 $6.10 Dollars in millions (except price assumptions) Exploration & Production 2006-08 Guidance Note: 2006-08 hedge information included in Appendix Note: If guidance has changed, previous guidance from 11/3/2005 is shown in italics directly below

An industry leader in production growth, cost efficiencies and reserves replacement Diligently managing increasing industry costs Strategy remains rapid development of our premier drilling inventory Delivering meaningful volume growth through expanded development drilling activity. Piceance is primary growth driver Long history of high drilling success, low finding costs Short time cycle investments, fast cash returns Long-term repeatable drilling inventory of significant proved undeveloped, probables, and possibles New opportunities contributing Experienced and talented work force Key Points Exploration & Production

Midstream Alan Armstrong Senior Vice President

Segment Profit Midstream Dollars in millions 4th Qtr Year 2005 2004 2005 2004 Segment Profit $112 $236 $471 $550 Nonrecurring: Depreciable Life Adjustment - 1 - 7 Gain on Asset Sales - (9) - (9) Insurance Arbitration Award - (94) - (94) Impairments - 17 - 17 Recurring Segment Profit $112 $151 $471 $471 4Q04 to 4Q05 financial highlights include: Significantly lower per unit NGL frac spreads Lower operating expenses Increased G&P fee revenue

4th Quarter and 2005 Highlights 2005 Opal TXP-5 construction commenced Construction of Tahiti and Blind Faith deepwater projects commenced Williams Partners L.P. (WPZ) successfully launched Hurricanes met with energetic response Sold $68MM in assets 4th Quarter Goldfinger and Triton production flowing on Devils Tower Significant progress on Overland Pass Pipeline project Opal TXP-4 acquisition 3Q '02 4Q '02 1Q '03 1Q '04 2Q '03 2Q '04 3Q '03 4Q '03 1Q 2Q 3Q 4Q 143 118.8 151.1 150.7 92.9 143.5 109 105.7 Recurring Segment Profit 102.2 78 112.3 108.3 53.6 98.5 69.4 65.6 Depreciation 40.8 40.8 38.8 42.4 39.3 45 39.6 40.1 2004 150 127 172 198 2005 175 155 170 162 Recurring Segment Profit + Depreciation Midstream

Note: If guidance has changed, previous guidance from 11/3/2005 is shown in italics directly below Midstream Dollars in millions 2006 2007 2008 Segment Profit $400-500 $410-530 $440-580 Annual DD&A 190-200 200-210 210-220 Segment Profit + DDA $590-700 $610-740 $650-800 Capital Spending $280-300 $230-270 $70-90 230-250 180-220 585-695 590-720 2006-08 Guidance 185-195 195-205 Major Growth Projects included in Guidance ($ Millions): Project Name - In Service Date 2006 2007 2008 Opal TXP IV (1Q 2006) $30 - - Opal TXP V (2Q 2007) 50 $15 - Blind Faith (3Q 2007) 90 85 - Wamsutter Phase II (4Q 2007) 10 65 - 1 1

Significant Progress Made on Growth Projects Western Deepwater 38 62 Western G&P Expansions Deepwater Expansions Devel. /Proposal Stage 2006 2007 2008 Spending $200MM - 400MM 40% 60% Western G&P Expansions ($75MM in guidance) Overland Pass Deepwater Expansions ($30MM in guidance) Under Negotiation 2006 2007 2008 Spending $700MM- 900MM Overland Pass Western Deepwater 30 10 60 60% 30% Opal Blind Faith 36 64 Blind Faith Opal TXP-V Opal TXP-IV Contracted/Approved 2006 2007 2008 Spending $280MM 65% 35% Midstream 10% In Guidance Not in Guidance

Overland Pass Pipeline Proposal Midstream Expected NGL Production End of Year 2008: Opal Processing Plant 65-70 MBPD Echo Springs Processing Plant 40-45 MBPD

Key Points Midstream Another record year despite hurricanes and lower commodity margins Continued to generate excess free cash Operating Cash Flow MLP Proceeds Asset sales Geographic diversification of processing assets mitigated decline in Mt. Belvieu frac spreads Significant progress on growth projects

Gas Pipeline Phil Wright Senior Vice President

Segment Profit Gas Pipeline Dollars in millions 4th Qtr Year 2005 2004 2005 2004 Segment Profit $93 $157 $586 $586 Nonrecurring: (Income)/expense related to prior periods 27 - (8) - Accrual of contingent refund obligation 10 - 10 - 1999 Fuel Tracker adjustment - - (14) - Write-off hydrostatic testing - - - 9 Recurring Segment Profit $130 $157 $574 $595 4Q04 to 4Q05 financial highlights include: Termination of Gray's Harbor contract - $5MM Higher fuel and operating expenses - $10MM

Transco: Central New Jersey project placed in-service 105 MDth/d of firm transportation serving the northeast market Successful open season for Sentinel to serve northeast market Precedent agreements signed for Potomac Expansion FERC certificate application filed for Leidy to Long Island Northwest: Successful open season for Parachute FERC certificate application filed in Jan 2006 1Q 2Q 3Q 4Q 2002 193.6 214.1 200.3 2004 213 210 211.7 223.9 2005 220.7 208 214.1 198 Gas Pipeline 4th Quarter and 2005 Accomplishments

2006 2007 2008 Segment Profit $475 - 5201 $585 - 655 $590 - 665 Annual DD&A 280 - 300 290 - 310 295 - 315 Segment Profit + DDA $755 - 820 $875 - 965 $885 - 980 Capital Spending $710 - 785 $390 - 490 $410 - 510 775 - 830 Dollars in millions 2006-08 Guidance Note: If guidance has changed, previous guidance from 11/03/05 is shown in italics directly below Gas Pipeline Includes: Pipeline safety costs of approximately $27 million to $35 million due to new accounting rule that requires certain pipeline assessment costs that have historically been capitalized to be recorded as expense beginning in 2006 Higher interest expense of $20 million at Gulfstream as a result of the October 2005 $850 million financing 600 - 680 290 - 300 300 - 310 300 - 390 885 - 965 485 - 530 1

2006-07 Capital Spending Detail $410 - 510 $390 - 490 $710 - 785 Total 230 - 250 180 - 220 95 - 105 - - 2 276 $180 - 260 $210 - 265 $340 - 405 Normal Maintenance/ Compliance 2008 2007 2006 Dollars in millions NWP 26" Replacement Expansion1 Note: - - Sum of ranges may not add due to rounding - - Ranges excludes AFUDC Gas Pipeline 20 - 35 305 - 370 600 - 680 1Major Growth Projects (in guidance): 2006 2007 2008 1st full yr Seg. Profit Parachute (In Service 1/07) $50 - 60 $8 Leidy to Long Island (In Service11/07) 10 - 15 $85 - 100 $1 - 5 18 Potomac (In Service 11/07) 5 - 10 55 - 65 1 - 5 11 Sentinel (In Service 11/08) 10 - 15 35 - 45 195 - 205 41 Greasewood (In Service 11/08) 25 - 30 2 - 4 180 - 235 300 - 390 120 - 155 Note: If guidance has changed, previous guidance from 11/03/05 is shown in italics directly below

Sentinel Nov 2008 Growth Projects and Opportunities Gulfstream Mainline Jan 2009 Leidy to Long Island Nov 2007 Potomac Nov 2007 Parachute Jan 2007 Pacific Connector Pipeline Late 2010 Prod. Area Mainline Exp Nov 2008 Mobile Bay South Summer 2008 Gas Pipeline Greasewood Nov 2008 Projects in proposal stage and not included in capital guidance Jackson Prairie Nov 2008

Key Points 2005 another strong year Strong cash flow provider Operational excellence Achieved new delivery records Met customer demand through hurricane challenges Customer focused Meeting market demands with new growth projects High rankings in customer satisfaction survey 2006 & forward Anticipate additional new growth projects Rate Case filings Gas Pipeline

Power Bill Hobbs Senior Vice President

Segment Profit/(Loss) Power Dollars in millions Segment Profit/(Loss) Before MTM Adjustment ($69) ($44) ($257) $77 Nonrecurring: Accrual for Regulatory & Litigation Contingencies/Settlements 69 - 87 - Impairments, Losses, Write-offs 23 - 23 - Expense Related to Prior Periods - - 7 - Recurring Segment Profit/(Loss) 22 (44) (140) 77 MTM Adjustment (Recurring) (22) (29) 138 (118) Recurring Segment (Loss) After MTM Adjustment - ($73) ($2) ($41) 4th Qtr Year 2005 2004 2005 2004 Note: MTM Adjustments (recurring) excludes $12mm paid in 3Q05 for buyout of gas supply contract Note: Might not sum due to rounding

Power 2005 - Segment Profit/(Loss) to Cash Flow From Operations 1 Includes nonrecurring adjustments which decrease reported Segment Loss by $117 million, $110 million of which is included in the "Working Capital/Other" column. A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com. 2 Includes $12 million of nonrecurring loss from MTM Previously Recognized. Recurring MTM Adjustment is $138 million. 3 Recurring Segment Profit/(Loss) After MTM is ($2)mm. Commodity Working Power & NG Capital/Other 2005 1 ($147) ($110) ($257) MTM Adjustments: Reverse Forward Unrealized MTM (Gains) (172) (172) Add Realized Gains from MTM Previously Recognized 2 298 298 Segment Profit/(Loss) after MTM Adjustments 3 (21) (110) (131) Total Working Capital Change 0 319 319 Power Segment CFFO (21) 209 188 Est. Working Capital Used for Other Business Units 0 (61) (61) Power Segment Standalone CFFO ($21) $148 $127 Dollars in millions Segment Profit/(Loss) Before MTM Adjustments

2006-08 Guidance Power Note: If guidance has changed, previous guidance from11/03/05 is shown in italics directly below 1 2006-2008 CFFO guidance assumes no changes in Working Capital. Changes in Working Capital are likely if future commodity prices are volatile or if counterparties exchange Letters of Credit for cash held by WMB. Payment of regulatory and litigation/settlement accruals are not included in CFFO guidance.

2005 Contracts Power Reducing Risk and Increasing Cash flow Certainty

2006 Contracts Power Reducing Risk and Increasing Cash flow Certainty

Capacity Sold by Year Power *Note: 2005A based on hedged position @ 3/31/05 Tutorial Schedules. 3,078 4,734 4,326 4,241 3,117 3,032 2,624 4,287 0 2,000 4,000 6,000 8,000 2005A* 2006F 2007F 2008F Total Capacity Sold Remaining Available Upside

Cash Flow Analysis Power Estimated undiscounted dollars in millions 1 2005 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. 2 Forecasted Hedged Cash Flows represents (1) the estimated cash flows from hedges such as resale of tolls, heat rate options, full requirements contracts and fixed price power and gas contracts and (2) the estimated value of the tolling (spread option) cash flows associated with those hedges. 3 Forecasted Merchant Cash Flows represents the tolling (spread option) cash flows which have not been hedged. 4 Working Capital & Other changes are zero in future years, as they are not reasonably estimable. Note: 2005 Forecast estimated as of 12/31/04. 2006 forward forecast estimated as of 12/31/05. Actual Cash Flows for 2005 includes impact of certain nonrecurring items. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding.

Dollars in millions 2006 Forecast: Recurring Segment Profit/(Loss) After MTM Adjustments 2005 Recurring Segment Loss After MTM Adjustments $ (2) - (2) Estimated cash flows from new contracts executed in 2005 40 - 50 Current and forecasted improvement in markets 0 - 70 No unplanned plant outages & hurricanes forecasted 10 - 20 Other 2 - 12 _______ 2006 Estimated Segment Profit After MTM Adjustments $50 - 150 Power

Key Points Positive CFFO for Power Segment and Power Standalone in 2005 Recurring 2005 Segment Loss after MTM improves $39 million over 2004 levels despite record high gas prices, mild weather, hurricanes and unplanned outages Outlook for 2006 improves based upon strength of new contracts and improving market conditions Power remains focused on creating additional cash flow certainty, generating EVA and reducing risk in our portfolio Continued success closing new risk-reducing contracts Power

2006-08 Consolidated Outlook Don Chappel CFO

Segment profit before MTM adjustment $1,240 - $1,580 Net Interest Expense (665) - (705) Other (Primarily General Corp. Costs) (90) - (120) Pretax Income 485 - 755 Provision for Income Tax (200) - (315) Income from Continuing Ops 285 - 440 Income/(Loss) from Discontinued Ops (5) - 0 Net Income $280 - 440 Diluted EPS $0.46 - $0.72 Recurring Income from Cont. Ops $303 - $458 Diluted EPS - Recurring $0.50 - $0.75 Diluted EPS - Recurring After MTM Adj. 1 $0.78 - $1.03 Dollars in millions, except per-share amounts 2006 Consolidated 2006 Forecast Guidance 1 Includes MTM adjustment of $280 million (pretax) Note: Fully diluted shares of 610 million

Dollars in millions 2006-08 Segment Profit After MTM Adj. Exploration & Production Midstream Gas Pipeline Power 1 Other / Corp. / Rounding Total 2006 2007 Consolidated $650 - 725 400 - 500 475 - 520 50 - 150 (55) - (35) $1,520 - 1,860 2008 $775 - 900 410 - 530 585 - 655 50 - 200 10 - (30) $1,830 - 2,255 $950 - 1,100 440 - 580 590 - 665 50 - 200 (15) - 35 $2,015 - 2,580 485 - 530 (65) - (85) 1 Includes MTM adjustments for 2006-2008 of $280 million (pretax), $210 million (pretax), and $200 million (pretax), respectively Note: If guidance has changed, previous guidance from 11/3/05 is shown in italics directly below 1820

2006 2007 2008 Exploration & Prod. $950 - 1,050 $950 - 1,050 $1,000 - 1,150 Midstream 280 - 300 230 - 270 70 - 90 Gas Pipeline 710 - 785 390 - 490 410 - 510 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $1,950 - 2,150 $1,600 - 1,800 $1,500 - 1,750 Dollars in millions Notes: - - Sum of ranges for each business line does not necessarily match total range If guidance has changed, previous guidance from 11/3/05 is shown in italics directly below Consolidated 2006-08 Capital Expenditures 1,425 - 1,625 600 - 680 300 - 390 1,825 - 2,050 230 - 250 180 - 220

1 Operating free cash flow is defined as cash flow from operations less capital expenditures, before dividend or principal payments Note: If guidance has changed, previous guidance from 11/3/05 is shown in italics directly below Dollars in millions 2006-08 Outlook Consolidated Segment Profit Reported MTM Adjustment After MTM Adjustment DD&A Cash Flow from Ops. Capital Expenditures Operating Free Cash Flow 1 2006 2007 $1,240 - 1,580 280 1,520 - 1,860 790 - 890 1,625 - 1,925 1,950 - 2,150 (325) - (225) 2008 $1,620 - 2,045 210 1,830 - 2,255 900 - 1,000 1,850 - 2,150 1,600 - 1,800 250 - 350 $1,815 - 2,380 200 2,015 - 2,580 1,000 - 1,100 2,200 - 2,600 1,500 - 1,750 700 - 850 1,600 - 2,025 230 1,425 - 1,625 (200) - (125) 1,250 - 1,550 270 1,825 - 2,050 425 - 525 1,820

Strong Operating Cash Flow Growth & Increasing Investment Opportunities 2003 2004 2005 2006 2007 2008 Cap Ex-Low 790 1415 1950 1600 1500 Cap Ex-High 790 1415 2150 1800 1750 CFFO-Low 588 1472 1450 1625 1850 2200 CFFO-High 588 1472 1450 1925 2150 2600 Debt to Cap 0.75 0.623 0.586 0.55 0.53 0.51 0.75 0.623 0.586 0.57 0.55 0.53 Cash Flow 1 / Cap Ex Debt / Cap 2 $1,472 $ Millions 1 Cash Flow from Continuing Operations (CFFO) 2 Debt to Capitalization = Total Debt / (Total Debt + Equity) 3 Includes Purchases of Long-term Investments 62% 55% to 57% 53% to 55% Consolidated $790 Opportunity Rich $1,625 to $1,925 $1,950 to $2,150 Declining Debt / Cap % $2,200 to $2,600 59% 51% to 53% $1,415 3 $1,450 $1,500 to $1,750 $1,600 to $1,800 Cap Ex $1,850 to $2,150 Increasing Cash Flow

Segment Profit Guidance Trend 2004 2005 2006 2007 2008 SPAM Low 1263 1577 1520 1830 2015 SPAM High 1263 1577 1860 2255 2580 SP Low 1381 1275 1175 1375 SP High 1381 1575 1475 1800 Cap Ex-Low 790 1175 1825 1450 Cap Ex-High 790 1350 2050 1650 $ Millions $1,578 (recurring) $1,520 to $1,860 $1,830 to $2,255 $1,263 (recurring) 1 Includes pretax MTM adjustments of ($118) in 2004, $137 in 2005, $280 in 2006, $210 in 2007, and $200 in 2008. Note: Growth percentages are to midpoint of range Consolidated Segment Profit After MTM Adjustments 1 $2,015 to $2,580 7.1% 24.9% 20.9% (Year-Over-Year Growth) (Year-Over-Year Growth) (Year-Over-Year Growth) 12.5% (Year-Over-Year Growth)

Drive/enable sustainable growth in EVA(r)/shareholder value Maintain a cash/liquidity cushion of $1.0 billion plus Continue to steadily improve credit ratios/ratings; ultimately achieving investment grade ratios Reduce risk in Power segment Opportunity rich Increasing focus and disciplined EVA(r)-based investments in natural gas businesses Attractive EVA-adding opportunities may require new capital If new capital is needed, choose optimal sources of capital Combination of growth in operating cash flows and EVA drives value creation Financial Strategy/Key Points Consolidated

Summary Steve Malcolm Chairman, President & CEO

Key Points Expect to grow key earnings measure at 15% rate Opportunity rich Investing in value growth Summary

Q&A

Non-GAAP Reconciliations

Non-GAAP Disclaimer This presentation includes certain financial measures, EBITDA, recurring earnings, free cash flow 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 presentation 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 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 presentation is also shown including Power mark-to-market adjustments. This presentation 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.

Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation

EBITDA Reconciliation Non-GAAP Reconciliation

* Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions 4Q 2005 Segment Contribution Non-GAAP Reconciliation

* Excluding equity earnings and income (loss) from investments contained in segment profit 2005 Segment Contribution Non-GAAP Reconciliation Dollars in millions

Net Income $280 - 440 Loss from Disc. Ops. 5 - 0 Net Interest 665 - 705 DD&A 790 - 890 Provision for Income Taxes 200 - 315 Other/Rounding 10 - 0 EBITDA $1,950 - 2,350 MTM Adjustments 280 EBITDA - After MTM Adj. $2,230 - 2,630 Dollars in millions 2006 Forecast EBITDA Reconciliation Feb 28 Guidance Non-GAAP Reconciliation

Power 1 $(235) - (135) 10 - 20 $(225) - (115) Gas Pipeline $475 - 520 280 - 300 $755 - 820 Segment Profit (Loss) DD&A Segment Profit Before DDA Other (Primarily General Corporate Expense & Investing Income) Rounding TOTAL E&P $650 - 725 335 - 375 $985 - 1,100 Midstream $400 - 500 190 - 200 $590 - 700 Total $1,240 - 1,580 790 - 890 $2,030 - 2,470 (90) - (120) 10 - 0 $1,950 - 2,350 Corp/ Other $(50) - (30) (25) - (5) $(75) - (35) 2006 Forecast Segment Contribution Non-GAAP Reconciliation Dollars in millions 1 Segment Profit is prior to MTM adjustments

Net Income $280 - 440 Less: Discontinued Operations 5 - 0 Income from Continuing Ops $285 - 440 Non-Recurring Items (Pretax) 30 Less Taxes @ Approx. 39% 12 Non-Recurring After Tax 18 Recurring Income from Cont. Ops $303 - 458 Recurring EPS $0.50 - $0.75 Mark-to-Market Adjustment (Pretax) Less Taxes @ 39% Mark-to-Market Adjust. After Tax Inc. from Cont. Ops after MTM Adj. Inc. from Cont. Ops after MTM Adj. EPS 280 (109) 171 $474 - 629 $0.78 - $1.03 2006 Forecast Guidance Reconciliation Non-GAAP Reconciliation Dollars in millions, except per-share amounts Feb 28 Guidance

Appendix

Fourth Quarter Segment Profit A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Dollars in millions Exploration & Production $206 $71 $206 $75 Midstream Gas & Liquids 112 236 112 151 Gas Pipeline 93 157 130 157 Power (69) (44) 22 (44) Other (30) (22) - (10) Segment Profit $312 $398 $470 $329 MTM Adjustments - Power (22) (29) Segment Profit after MTM Adjustments $448 $300 Memo: Power after MTM adjustments $0 $(73) Consolidated Reported Recurring 4Q05 4Q04 4Q05 4Q04

2005 Segment Profit Reported Recurring 2005 2004 2005 2004 Exploration & Production $587 $236 $558 $251 Midstream Gas & Liquids 471 550 471 471 Gas Pipeline 586 586 574 595 Power (257) 77 (140) 77 Other (104) (43) (23) (13) Segment Profit $1,283 $1,406 $1,440 $1,381 MTM Adjustments 138 (118) Segment Profit after MTM Adjustments $1,578 $1,263 Memo: Power after MTM adjustments ($2) $(41)1 Dollars in millions Consolidated A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. 1 Includes impact of legacy natural gas portfolio that was liquidated in 1Q04. / corrected

Debt Balance1 Scheduled Debt Retirements & Amortization (6) Debt Balance @ 6/30/05 7,744 7.5% Scheduled Debt Retirements & Amortization (23) Debt Balance @ 9/30/05 $7,721 7.5% Scheduled Debt Retirements & Amortization (8) Debt Balance @ 12/31/05 $7,713 7.6% Fixed Rate Debt @ 12/31/05 $7,066 7.7% Variable Rate Debt @ 12/31/05 $647 6.3% Avg. Cost 1 Debt is long-term debt due within 1 year plus long-term debt. Dollars in millions Consolidated Debt Balance @ 12/31/04 $7,962 7.4% Scheduled Debt Retirements & Amortization (216) Capitalized Lease 4 Debt Balance @ 3/31/05 7,750 7.4%

2005 Cash Information Consolidated 1 $273 MM of proceeds related to settlement of purchase contract underlying FELINE PACS

Consolidated Diluted EPS from Cont. Ops. $0.34 $0.07 $0.01 $0.11 $0.53 Recurring EPS 0.33 0.11 ($0.01) $0.28 0.72 Recurring EPS after MTM Adj. 0.22 0.17 0.22 0.26 0.86 Average Shares (MM) 599 579 581 609 606 2005 1Q 2Q 3Q 4Q Total Diluted EPS from Cont. Ops. - ($0.03) $0.03 $0.17 $0.17 Recurring EPS 0.01 0.10 0.26 0.12 0.49 Rec. EPS after MTM Adj. 0.14 0.03 0.09 0.09 0.35 Average Shares (MM) 519 522 530 586 536 2004 1Q 2Q 3Q 4Q Total EPS Metrics

Interest on Long-Term Debt $574 - $591 Amortization Discount/Premium and other Debt Expense 35 - 43 Credit Facilities: (incl. Commitment Fees plus LC Usage) 42 - 52 Interest on other Liabilities 22 - 32 Interest Expense $673 - $718 Less: Capitalized Interest (8) - (13) Net Interest Expense Guidance $665 - $705 Dollars in millions 2006 Consolidated 2006 Interest Expense Guidance

2005 Effective Tax Rates Consolidated

2006 2007 2008 Fixed Price at the basin: Volume (MMcfe/d) 299 172 73 Price ($/Mcfe) $3.82 $3.90 $3.96 NYMEX Collars: Volume (MMcfe/d) 65 15 - Price ($/Mcfe) $6.62 - $8.42 $6.50 - $8.25 At the Basin Collars: NWPL Rockies1 Volume (MMcfe/d) 50 50 - Price ($/Mcfe) $6.05 - $7.90 $5.65 - $7.45 EPNG San Juan1 Volume (MMcfe/d) 80 - Price ($/Mcfe) $5.85 - $9.33 Mid-Continent1 Volume (MMcfe/d) 20 - Price ($/Mcfe) $6.76 - $11.83 Dollars in millions Exploration & Production 2006-08 Hedge Update 1 Please note basin locations not NYMEX

4Q 2005 Net Realized Price Calculation Exploration & Production

Note: Based on actual realized prices, contractual obligations, shrink, fuel, actual equity liquids percentages, etc. Average Realized Margin shown for 2001-2005. Does not include Discovery volumes. Midstream Margins Above Average Domestic NGL Average Realized Net Margin and Volumes by Quarter Margin (Cents / Gallon) Total Production & Equity Volumes by Quarter (MM Gallons) Margin Total NGL Prod (MM Gals) Equity NGL Sales (MM Gals) Avg. Realized Margin

Midstream Strong Free Cash Flow Dollars in millions Note: - - Segment Profit is stated on a recurring basis. Segment Profit for 2004 has been restated to reflect reclassifications - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges. - - Margin uplift represents actual realized margin in excess of forecasted margin. 0 100 200 300 400 500 600 700 800 Capital 2004 Seg Profit + DDA Seg Profit & DDA Discretionary Expansion Margin Uplift Base Capital Spending Historic Expansion Discretionary Expansion Maintenance Well Connects Capital Seg Profit + DDA 2005 Capital Seg Profit + DDA 2006 Capital Seg Profit + DDA 2007 Capital Seg Profit + DDA 2008

2005 vs 2006 Segment Profit Gas Pipeline 2005 Reported Segment Profit $586 Non-recurring Items (12) 2005 Recurring Segment Profit 574 Pipeline Safety Costs - Acctg Change (31) Gulfstream Interest Exp/Completion Fee 1 (15) Subtotal 528 Pacific Connector (6) - 0 Higher DDA/Operating Expenses (50) -(8) 2006 Segment Profit Range $475 - 520 1 Lower equity earnings from Gulfstream LLC in 2006 due to Gulfstream LLC issuing $850 million of new long term debt in October 2005. Note: May not add due to rounding

2003 2004 2005 2006 2007 2008 Mandatory 106 199 329 584 180 165 Maintenance 43 34 40 65 60 55 Expansion 376 22 25 100 200 240 Seg Profit + DDA 862 857 841.4 788 920 933 Gas Pipeline Dollars in millions Strong Free Cash Flow 2004 2005 2006 2007 Seg Profit + DDA Seg Profit + DDA Capital Spending Expansion Maintenance Mandatory Note: - - Segment Profit is stated on a recurring basis. - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges for 2006 - 2008. 2008

4Q05 Financial Statement Changes for Derivatives During 4Q05, Williams reported the following changes related to its derivative portfolio: The net change in Derivative Assets and Liabilities for E&P was positive reflecting the 2006 decrease in gas prices against a short derivative position. The net change in Derivative Assets and Liabilities for Power was positive, reflecting the increased economic value of the Power derivatives primarily due to the rise in 2007 forward gas prices against our long derivative position. Additional gains were made on price decreases on our short power position. Power NOTE: Change in OCI shown is economic change before taxes. Therefore, change shown does not tie to balance sheet change which is net of taxes.

West Undiscounted Cash Flows Power Expected undiscounted dollars in millions 1 2005 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. 2 Forecasted Hedged Cash Flows represents (1) the estimated cash flows from hedges such as resale of tolls, heat rate options, full requirements contracts and fixed price power and gas contracts and (2) the estimated value of the tolling (spread option) cash flows associated with those hedges. 3 Forecasted Merchant Cash Flows represents the tolling (spread option) cash flows which have not been hedged. Note: 2005 Forecast estimated as of 12/31/04. 2006 forward forecast estimated as of 12/31/05. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding.

Mid-Con Undiscounted Cash Flows Power Expected undiscounted dollars in millions 1 2005 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. 2 Forecasted Hedged Cash Flows represents (1) the estimated cash flows from hedges such as resale of tolls, heat rate options, full requirements contracts and fixed price power and gas contracts and (2) the estimated value of the tolling (spread option) cash flows associated with those hedges. 3 Forecasted Merchant Cash Flows represents the tolling (spread option) cash flows which have not been hedged. Note: 2005 Forecast estimated as of 12/31/04. 2006 forward forecast estimated as of 12/31/05. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding.

East Undiscounted Cash Flows Power Expected undiscounted dollars in millions 1 2005 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. 2 Forecasted Hedged Cash Flows represents (1) the estimated cash flows from hedges such as resale of tolls, heat rate options, full requirements contracts and fixed price power and gas contracts and (2) the estimated value of the tolling (spread option) cash flows associated with those hedges. 3 Forecasted Merchant Cash Flows represents the tolling (spread option) cash flows which have not been hedged. Note: 2005 Forecast estimated as of 12/31/04. 2006 forward forecast estimated as of 12/31/05. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding.

Corp./ E&P Midstream Power Other Total Dollars in millions As of 12/31/05 1Reflects net amount of margins out less margins in. WMB Collateral Outstanding $1 $0 $47 $0 $48 0 1 13 0 14 1 1 60 0 62 745 242 283 91 1,361 746 243 343 91 1,423 1,147 225 322 91 1,785 $(401) $18 $21 $0 $(362) Margins & Ad. Assurances1 Prepayments Subtotal Letters of Credit Total as of 12/31/05 Total as of 9/30/05 Change

Estimated dollars in millions WMB Collateral Sensitivity Note: The margin numbers above assume only the forward marginable position values are included.

Enterprise Risk Management 1 Assumes a correlated movement in prices across all commodities, including spreads, for all Williams business units combined. 2 Assumes a non-correlated change in West power prices only, no change in power volatility, full extrinsic value not included. Heat rate and position change associated with Spark Spread increase is consistent across all months. Cash flow ranges are not linear. 3 Assumes a non-correlated change in NGL processing spread (i.e. change in NGL price only). Estimated dollars in millions (except price assumptions)

The Williams Companies, Inc.

exv99w3

Exhibit 99.3

NYSE: WMB

Date: Feb. 28, 2006

Williams Replaces 277 Percent of 2005 U.S. Natural Gas Production
Total Domestic and International Proved Reserves Grow to 3.6 Tcfe

TULSA, Okla. – Williams (NYSE:WMB) announced today that its domestic and international proved natural gas and oil reserves as of Dec. 31, 2005, increased to 3.6 trillion cubic feet equivalent (Tcfe).

Reserves in the United States increased 13.3 percent to approximately 3.4 Tcfe, compared with approximately 3.0 Tcfe a year earlier. More than 99 percent of Williams’ U.S. proved reserves are natural gas.

International reserves increased slightly to approximately 37 million barrels of oil equivalent in 2005 compared with approximately 36 million barrels of oil equivalent in 2004. Sixty-five percent of Williams’ international proved reserves are crude oil and liquids; the remainder is natural gas.

Williams attributed the majority of its U.S. reserves additions to drilling and to increasing the density of well spacing below the surface in the Piceance Basin, along with drilling in the Powder River Basin and other basins. Williams also acquired a position in the Fort Worth Basin in 2005.

In 2005, Williams had a drilling success rate of approximately 99 percent. The company drilled 1,629 gross wells, of which 1,617 were successful.

Williams’ drilling activity in 2005 resulted in the addition of 603 billion cubic feet equivalent (Bcfe) in net reserves. Williams added 451 Bcfe in net reserves in 2004 and 408 Bcfe in net reserves in 2003. The company’s three-year finding and developing costs in the U.S. averaged 92 cents per Mcfe.

“We continue to rapidly develop our long-term drilling inventory at a highly successful rate,” said Ralph Hill, senior vice president of Williams’ exploration and production business. “This is a credit to the quality of our highly skilled employees and our portfolio, which consists of large, well-defined resources.

“Williams is focused on delivering measurable and meaningful growth in both volumes and reserves. Over the past three years, we have added more than 1.4 trillion cubic feet equivalent in domestic net reserves from our drilling activities,” Hill said.

Williams replaced its 2005 U.S. natural gas production of 224 billion cubic feet equivalent (Bcfe) at a ratio of 277 percent. A reserves reconciliation follows the main text in this news release.

Average daily production from domestic and international interests was approximately 662 million cubic feet of gas equivalent (MMcfe), compared with 564 MMcfe for the same period in 2004 – an increase of

approximately 17 percent.

Production solely from domestic interests increased 18 percent to approximately 612 MMcfe in 2005 from 519 MMcfe in 2004.

In 2006, Williams plans to invest $950 million to $1.05 billion in capital to develop production from its long-term drilling inventory.

Williams’ exploration and production business primarily develops natural gas reserves in the Piceance, Powder River, San Juan, Arkoma and Fort Worth basins in the United States.

Williams also owns an approximately 69 percent interest in APCO Argentina (NASD:APAGF), a separately traded oil and gas company with properties in Argentina, and a 10 percent interest in the La Concepcion oil field in Venezuela.

Approximately 97 percent of Williams’ year-end 2005 U.S. proved reserves estimates were audited by Netherland, Sewell & Associates, Inc., who in their judgment determined the estimates to be reasonable in the aggregate for each basin.

Reserves estimates related to properties underlying the Williams Coal Seam Gas Royalty Trust (NYSE:WTU), were prepared by Miller and Lents, LTD. These properties comprise another 2 percent of Williams’ total U.S. proved reserves.

Proved reserves estimates for APCO Argentina were prepared by Ryder Scott Company.

The reserve replacement ratio of 277 percent was calculated by dividing the sum of changes (acquisitions, divestitures, additions and revisions) to the estimated proved reserves during 2005 by Williams’ 2005 production of 224 Bcfe.

The three-year average finding and development cost of 92 cents per Mcfe in the United States was calculated by dividing total capital spent, including facilities and acquisitions, by the change in proved reserves balances for the retained basins over the three-year period, adding back production sold.

For purposes of converting volumes of crude oil and liquids reserves to a natural-gas-equivalent measure in this report, the company used a ratio of one barrel to 6,000 cubic feet.

Proved reserves are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under assumed economic conditions.

U.S. Proved Reserves Reconciliation
Figures in billion cubic feet equivalent of natural gas


Proved reserves Dec. 31, 2004	2,986
Acquisitions	28
Divestitures	(11	)
Additions and revisions	603
Production	(224	)

Proved reserves Dec. 31, 2005	3,382

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

		Sharna Reingold
		Williams (investor relations)
		(918) 573-2078

# # #

Portions of this document may constitute “forward-looking statements” as defined by federal law. Although the company believes any such statements are based on reasonable assumptions, there is no assurance that actual outcomes will not be materially different. Any such statements are made in reliance on the “safe harbor” protections provided under the Private Securities Reform Act of 1995. Additional information about issues that could lead to material changes in performance is contained in the company’s annual reports filed with the Securities and Exchange Commission.

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