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): August 3, 2006

The Williams Companies, Inc.

(Exact name of registrant as specified in its charter)



Delaware	1-4174	73-0569878
(State or other	(Commission	(I.R.S. Employer
jurisdiction of	File Number)	Identification No.)
incorporation)



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))


Item 2.02.		Results of Operations and Financial Condition.

On August 3, 2006, The Williams Companies, Inc. (“Williams” or the “Company”) issued a press release announcing its financial results for the quarter ended June 30, 2006. A copy of the press release and its accompanying 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 its accompanying 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 August 3, 2006.

The slide presentation is 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 August 3, 2006, and its accompanying highlights and reconciliation schedules, publicly announcing its second quarter 2006 financial results.

Exhibit 99.2		Copy of Williams’ slide presentation to be utilized during the August 3, 2006, public conference call and webcast.

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: August 3, 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 August 3, 2006, and its accompanying highlights and reconciliation schedules, publicly announcing its second quarter 2006 financial results.

Exhibit 99.2		Copy of Williams’ slide presentation to be utilized during the August 3, 2006, public conference call and webcast.

exv99w1

Exhibit 99.1

NYSE:WMB

Date: Aug. 3, 2006

Williams Reports Second-Quarter 2006 Financial Results

	•		99% Increase in Recurring Income After Mark-to-Market Adjustment

	•		Net Income Significantly Reduced by Legacy Litigation Settlement and Charges

	•		Company Raises Profit and Cap-Ex Guidance for 2006-2008: Key 2006 EPS Measure Rises 19%

	•		2Q Natural Gas Production Up 20% Compared With Last Year

	•		Williams Outlines Goal to Accelerate Drop-Downs to MLP


Quarterly Summary Information	2Q 2006						2Q 2005
Per share amounts are reported on a diluted basis	millions			per share			millions		per share

Income (loss) from continuing operations	$	(63.9	)	$	(0.11	)	$	40.7	$	0.07
Income (loss) from discontinued operations	$	(12.1	)	$	(0.02	)	$	0.6	$	0.00

Net income (loss)	$	(76.0	)	$	(0.13	)	$	41.3	$	0.07

Recurring income from continuing operations*	$	112.6		$	0.19		$	65.9	$	0.11
After-tax mark-to-market adjustments	$	85.4		$	0.14		$	33.6	$	0.06

Recurring income from continuing operations — after mark-to-market adjustment*	$	198.0		$	0.33		$	99.5	$	0.17


Year-to-Date Summary Information	YTD 2006						YTD 2005
Per share amounts are reported on a diluted basis	millions			per share			millions			per share

Income from continuing operations	$	67.2		$	0.11		$	242.9		$	0.41
Income (loss) from discontinued operations	$	(11.3	)	$	(0.02	)	$	(0.5	)	$	0.0

Net income	$	55.9		$	0.09		$	242.4		$	0.41

Recurring income from continuing operations*	$	248.5		$	0.42		$	264.3		$	0.45
After-tax mark-to-market adjustments	$	106.4		$	0.17		$	(32.4	)	$	(0.06	)

Recurring income from continuing operations — after mark-to-market adjustment*	$	354.9		$	0.59		$	231.9		$	0.39


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

Williams — 2^nd Quarter Results — Aug. 3, 2006 — Page 1 of 12

TULSA, Okla. — Williams (NYSE:WMB) today announced a second-quarter 2006 unaudited net loss of $76.0 million, or a loss of 13 cents per share on a diluted basis, compared with net income of $41.3 million, or 7 cents per share, for second-quarter 2005.

Results for second-quarter 2006 were significantly reduced by the after-tax impact of three legacy litigation charges totaling approximately $175 million. The combined impact of the charges on a pre-tax basis is $267.9 million.

These items include a $160.7 million pre-tax charge associated with an agreement in principle to settle securities litigation filed on behalf of purchasers of Williams’ securities between 2000 and 2002; an $88.0 million pre-tax accrual, including $20 million in interest, associated with the Gulf Liquids jury verdicts this week; and a $19.2 million pre-tax loss from discontinued operations primarily related to an environmental indemnity arbitration ruling associated with a former business.

These nonrecurring charges and the effect of mark-to-market accounting obscure the company’s strong performance overall. Margins for the company’s natural gas liquids sales remain at historic highs and Williams continues to increase its natural gas production in the western United States.

Year-to-date through June 30, Williams reported net income of $55.9 million, or 9 cents per share on a diluted basis, compared with net income of $242.4 million, or 41 cents per share, for the first half of 2005.

On a basis to remove the effect of nonrecurring items and mark-to-market accounting, Williams earned 33 cents per share in second-quarter 2006, almost doubling the 17 cents per share from the same period a year ago.

For the first half of 2006, Williams earned 59 cents per share on a basis adjusted to remove the effect of nonrecurring items and mark-to-market accounting. That represents a 51 percent improvement compared with 39 cents per share on the same basis for the first half of 2005.

Higher results in 2006 are primarily attributable to increased natural gas liquids sales margins and increased natural gas production. Additional details about the nonrecurring items and mark-to-market adjustment for the second quarter and the first half of the year are included in this news release.

Recurring Results Adjusted to Remove the 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.

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 — increased 99 percent from a year ago to $198.0 million, or 33 cents per share, in second-quarter 2006 from $99.5 million, or 17 cents per share in second-quarter 2005.

Williams — 2^nd Quarter Results — Aug. 3, 2006 — Page 2 of 12

For the first six months of 2006, recurring income from continuing operations — adjusted to remove the effect of mark-to-market accounting — was $354.9 million, or 59 cents per share, an increase of 53 percent compared with $231.9 million, or 39 cents per share, for the first half of 2005.

The improvement in 2006 is primarily the result of robust sales margins for natural gas liquids; increased natural gas production, particularly in the Piceance and Powder River basins; increased gathering and processing revenue in Midstream; and improved results in Power’s gas and power portfolios.

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.

Williams Increases Guidance for 2006-2008

Williams has raised its guidance for 2006-2008 based on the company’s strong first-half operations performance in 2006, anticipated increases in natural gas production volumes, and its outlook for crude oil prices — a key factor that has driven record-level sales margins for natural gas liquids.

The company now expects 95 cents to $1.20 for earnings per share in 2006 on a recurring basis adjusted to remove the effect of mark-to-market accounting, an increase of 19 percent compared with the previous expectation of 78 cents to $1.03.

Williams also is raising its expectations for consolidated segment profit for 2006 through 2008 on a recurring basis adjusted to remove the effect of mark-to-market accounting.

Updated Guidance — Recurring Segment Profit Adjusted for Mark-to-Market Effect


	NEW	PREVIOUS
2006	$1.69 billion-$2.01 billion	$1.52 billion-$1.86 billion
2007	$1.97 billion-$2.475 billion	$1.83 billion-$2.255 billion
2008	$2.2 billion-$2.875 billion	$2.015 billion-$2.58 billion

The company’s overall expected capital budget has increased, as well. The increase in planned capital expenses is primarily for projects that support additional natural gas development, particularly in the Piceance Basin.

Updated Cap-Ex Guidance


	NEW	PREVIOUS
2006	$2.2 billion-$2.4 billion	$1.95 billion-$2.15 billion
2007	$1.775 billion-$1.975 billion	$1.6 billion-$1.8 billion
2008	$1.575 billion-$1.825 billion	$1.5 billion-$1.75 billion

Williams — 2^nd Quarter Results — Aug. 3, 2006 — Page 3 of 12

CEO Perspective

“Williams’ solid performance demonstrates that we’re executing our business plan and taking action to deliver strong sustainable increases in shareholder value,” said Steve Malcolm, chairman, president and chief executive officer.

“So far in 2006, we have invested $1 billion in our businesses, increased our dividend by 20 percent, completed a major transaction with our master limited partnership, eliminated virtually all of our secured debt, improved our credit ratings, and reached an agreement in principle to settle securities litigation.

“And although natural gas prices softened following a mild winter, these conditions have benefited our Midstream business tremendously. The combination of lower prices for natural gas and higher prices for crude oil has pushed the sales margins for natural gas liquids to new highs — highs that could become more of the norm based on the global factors that drive demand for crude oil.

“Now we’re raising our guidance for earnings per share by 19 percent on a recurring basis adjusted for mark-to-market accounting. Equally important, we’re looking at breakout growth in 2007 and beyond.

“We’re drilling more natural gas wells than ever before, we’re getting a boost from our previous deepwater investments, we’re forecasting continued strength in NGL margins, and we’re expecting new rates on our interstate pipeline systems to be effective early in 2007.”

Business Segment Performance

Consolidated results include segment profit for Williams’ primary businesses — Exploration & Production, Midstream Gas & Liquids, Gas Pipeline and Power — as well as results reported in the Other segment.

Williams’ businesses reported consolidated segment profit of $292.9 million in second-quarter 2006, an increase of 14 percent compared with $256.4 million a year ago.

Higher results in second-quarter 2006 are primarily attributable to robust margins for natural gas liquids sales and increased natural gas production, partially offset by higher operating costs and the $68 million portion of the Gulf Liquids litigation accrual recorded at Midstream. Results for the same period in 2005 were affected by a $49.1 million impairment charge to an equity investment in the Other segment.

On a basis adjusted to remove the effect of nonrecurring items and mark-to-market accounting, Williams had recurring consolidated segment profit of $499.3 million in second-quarter 2006, compared with $355.7 million a year ago — an increase of 40 percent.

2Q Consolidated Recurring Segment Profit Adjusted for Mark-to-Market Effect


	2Q '06		2Q '05
	(millions)		(millions)
Segment profit	$	292.9	$	256.4
Nonrecurring adjustments	$	68.0	$	44.5

Recurring segment profit	$	360.9	$	300.9
Reverse forward unrealized mark-to-market (gains) losses	$	38.6	$	(22.1	)
Add realized mark-to-market gains that were previously recognized	$	99.8	$	76.9

Recurring segment profit after mark-to-market adjustments	$	499.3	$	355.7

Williams — 2^nd Quarter Results — Aug. 3, 2006 — Page 4 of 12

YTD Consolidated Recurring Segment Profit Adjusted for Mark-to-Market Effect


	YTD '06			YTD '05
	(millions)			(millions)
Segment profit	$	705.2		$	766.1
Nonrecurring adjustments	$	59.7		$	35.2

Recurring segment profit	$	764.9		$	801.3
Reverse forward unrealized mark-to-market gains	$	(4.4	)	$	(243.2	)
Add realized mark-to-market gains that were previously recognized	$	176.9		$	189.9

Recurring segment profit after mark-to-market adjustments	$	937.4		$	748.0

For the first half of 2006, Williams’ businesses reported consolidated segment profit of $705.2 million, a decrease of 8 percent compared with $766.1 million for the first half of 2005. Results in the first half of 2005 benefited from $243.2 million of forward unrealized mark-to-market gains in Power, compared with only $4.4 million in the first half of 2006. The 2006 period also includes the $68 million Gulf Liquids litigation accrual.

On a basis adjusted to remove the effect of nonrecurring items and mark-to-market accounting, Williams had recurring consolidated segment profit of $937.4 million for the first half of 2006, compared with $748.0 million for the first half of 2005 — an increase of 25 percent.

The improvement in 2006 on an adjusted basis is primarily the result of significantly higher results in Midstream, Power and Exploration & Production.

Exploration & Production: Segment Profit and Volumes Up 20 Percent

Exploration & Production includes natural gas production and development in the U.S. Rocky Mountains, San Juan Basin and Mid-Continent, and oil and natural gas operations in South America.

This business reported second-quarter 2006 segment profit of $119.8 million, comparable to segment profit of $118.3 million a year ago. The price for production sold was relatively flat from quarter-to-quarter, including the effect of legacy hedge positions. During the second quarter of 2006, Williams realized net domestic average prices of $4.18 per thousand cubic feet equivalent (Mcfe), compared with $4.16 a year ago.

The benefit of higher production volumes in the second quarter of 2006 was offset by increased lease operating expenses, including $9 million of prior-period expenses and higher work-over expenses; higher depreciation, depletion and amortization; and higher general and administrative expenses.

For the first six months of 2006, Exploration & Production reported segment profit of $267.4 million, an increase of 20 percent compared with $222.0 million for the first half of 2005.

Williams — 2^nd Quarter Results — Aug. 3, 2006 — Page 5 of 12

The improvement in the first half of 2006 primarily reflects increased production volumes; higher net realized average prices for production sold in the first quarter; and an $11 million increase in unrealized gains from hedge ineffectiveness and forward mark-to-market gains on certain basis swaps not designated as hedges.

These increases were partially offset by the same factors previously noted for the second quarter, as well as the absence of an $8 million gain in 2005 on the sale of certain assets.

Average daily production from domestic and international interests was approximately 786 million cubic feet of gas equivalent (MMcfe) in second-quarter 2006, compared with 652 MMcfe in the first half of 2005 — an increase of 20 percent.

Second-quarter 2006 average daily production in the Piceance Basin was 413 MMcfe — up 34 percent compared with second-quarter 2005 production of 309 MMcfe. Production in the Powder River Basin increased, too — up 23 percent to 137 MMcfe, compared with 111 MMcfe a year ago.

Williams now has 23 rigs operating in the Piceance Basin of western Colorado — 10 more than it had at this time a year ago. The rig count includes six new-generation drilling rigs that are purpose-built for conditions in the tight-sands development. So far, Williams has seen an improvement in drilling efficiency of approximately 25 percent with the new rigs. Four more are scheduled for delivery this year.

Williams now plans to invest $1.15 billion to $1.25 billion in Exploration & Production in 2006 — an increase of $200 million from its previous plan. These investments primarily focus on increasing the pace of developing the company’s natural gas reserves.

Williams also has increased its expectation for segment profit from Exploration & Production in 2006. The company now expects $550 million to $650 million in segment profit, an increase of $25 million from guidance provided in May this year. The increase is the result of anticipated increases in production volumes.

Midstream Gas & Liquids: 2Q Recurring Segment Profit Rises 82 Percent

Midstream provides gathering and processing services for oil and gas producers, along with natural gas liquids (NGL) services and olefins production.

This business reported segment profit of $130.7 million in the second quarter, up 20 percent compared with $109.1 million a year ago.

Excluding a nonrecurring charge of $68 million related to the Gulf Liquids litigation accrual, Midstream posted $198.7 million of recurring segment profit — an increase of 82 percent compared with a year ago.

The dramatic increase in Midstream’s results is primarily because of historic highs for NGL sales margins. This is the eighth consecutive quarter that NGL sales margins have remained above the company’s five-year average, reflecting sustained strength in high crude oil prices that support strong NGL prices. Williams markets natural gas liquids via equity volumes the company retains as payment-in-kind under certain processing contracts.

Williams — 2^nd Quarter Results — Aug. 3, 2006 — Page 6 of 12

In addition, Williams experienced high growth in production handling volumes and revenues in the deepwater Gulf of Mexico, and higher fee-based gathering and processing revenues.

In second-quarter 2006, Midstream sold 361.3 million gallons of NGL equity volumes — about 7 percent higher than equity sales of 338.3 million gallons in second-quarter 2005.

For the first six months of 2006, Midstream reported segment profit of $282.2 million, an increase of 19 percent compared with $237.7 million for the first half of 2005.

The improvement in 2006 primarily reflects a $79 million increase in natural gas liquids sales margins; significantly higher production handling volumes and revenues in the deepwater Gulf of Mexico; and higher fee-based gathering and processing revenues. These increases were partially offset in the first half by the Gulf Liquids litigation accrual and higher costs from maintenance expenses.

Year-to-date through June 30, Midstream sold 695.0 million gallons of domestic NGL equity volumes, a decrease of 6 percent compared with equity sales of 737.0 million gallons in the first half of 2005. Lower volumes of equity sales in the first half of 2006 were primarily the result of an increase in volumes subject to fee-based processing contracts in the first quarter.

The Cameron Meadows natural gas plant in Louisiana’s Cameron Parish has been processing approximately 250-270 million cubic feet per day (MMcf/d) since returning to partial service in February. The facility is scheduled to return to its full design capacity of 500 MMcf/d by the end of August. The plant was damaged by Hurricane Rita last September.

In May, Williams reached an agreement with a third-party to develop the Overland Pass pipeline. Williams initiated the 750-mile project last year to provide an additional outlet for natural gas liquids produced at the company’s Wyoming processing plants. The third-party has reimbursed Williams’ development costs and will construct the pipeline. Williams retained a 1 percent ownership interest and has the option to increase its ownership to 50 percent. Start-up is planned for early 2008.

During the second quarter, Williams also completed a transaction that involved the drop-down of a 25.1 percent interest in Williams Four Corners LLC gathering and processing assets to Williams Partners L.P. (NYSE:WPZ) for $360 million. The partnership financed the transaction with $150 million in private debt and an equity offering that produced approximately $225 million in net proceeds.

Williams today said its goal is to complete similar transactions during the next six months — ranging in value from $1 billion to $1.5 billion — involving its gathering and processing assets with Williams Partners L.P. Williams has a portfolio of qualifying assets that support annual drop-downs of $1 billion to $2 billion through 2008.

The terms, including price, of any transactions between the company and the partnership are subject to approval by the boards of directors of each Williams and the general partner of Williams Partners. The terms also will be subject to approval by the conflicts committee of the board of directors of the general partner of Williams Partners.

Williams — 2^nd Quarter Results — Aug. 3, 2006 — Page 7 of 12

Williams is raising its guidance again for segment profit it expects from Midstream in 2006 based on its outlook for strong NGL prices. The company now expects $550 million to $675 million in segment profit for this business. The company’s prior guidance in May was $500 million to $600 million in segment profit for Midstream.

Gas Pipeline: Northwest Files Rate Case, Transco to Follow

Gas Pipeline primarily delivers natural gas to markets along the Eastern Seaboard, in the Northwest, and in Florida. This business reported second-quarter 2006 segment profit of $122.7 million, down 25 percent compared with $164.5 million a year ago.

The second quarter of 2005 benefited from $21.7 million in prior-period adjustments, including a $17.1 million reduction to pension expense. Results in the second-quarter of 2006 benefited from $2.8 million in higher equity earnings, which were more than offset by higher operating and maintenance costs and higher selling, general and administrative costs.

For the first six months of 2006, Gas Pipeline reported segment profit of $257.4 million, down 22 percent compared with $331.9 million for the first half of 2005.

The reduction in results for the first half of 2006 is attributable to higher operating and maintenance costs and higher selling, general and administrative costs, including the absence of $34.8 million in prior-period adjustments recorded in the first half of 2005.

Transco and Northwest Pipeline are proceeding with new rate case filings at the Federal Energy Regulatory Commission to reflect, among other things, current levels of operating costs and rate base. Northwest Pipeline filed its rate case on June 30 and Transco expects to file its rate case by Aug. 31. The new rates for both pipelines are expected to be effective, subject to refund, in first-quarter 2007.

Separately, FERC has approved Transco’s application for an expansion project to add 100,000 dekatherms of firm capacity between Leidy, Pa., and Long Island, N.Y. Construction on the $121 million project is slated to begin in January 2007, with a projected in-service date of November 2007.

Williams also owns a 50-percent interest in the Gulfstream Natural Gas System, L.L.C., joint venture. In May, Gulfstream reached a new customer agreement that will require the first expansion to the original mainline capacity of nearly 1.1 billion cubic feet. Gulfstream expects to begin construction of the 17-mile, 155,000-dekatherm Phase IV expansion in January 2008.

Williams continues to expect $475 million to $520 million in segment profit from Gas Pipeline in 2006.

Williams — 2^nd Quarter Results — Aug. 3, 2006 — Page 8 of 12

Power: Solid Performance as Expected

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

2Q Power Recurring Segment Profit (Loss) Adjusted for Mark-to-Market Effect


	2Q '06			2Q '05
	(millions)			(millions)
Segment loss	$	(79.6	)	$	(75.0	)
Nonrecurring adjustments	$	0.0		$	13.1

Recurring segment loss	$	(79.6	)	$	(61.9	)
Mark-to-market adjustments — net	$	138.4		$	54.8

Recurring segment profit (loss) after mark-to-market adjustments	$	58.8		$	(7.1	)

Power reported a second-quarter 2006 segment loss of $79.6 million, comparable to a segment loss of $75.0 million for second-quarter 2005. Results include the effect of forward noncash unrealized mark-to-market gains and losses.

The slight decrease is primarily the result of lower noncash unrealized mark-to-market gains, partially offset by the absence of a $13.1 million litigation accrual in 2005 and higher accrual earnings in 2006.

On a basis adjusted for the effect of mark-to-market accounting, Power reported recurring segment profit of $58.8 million in second-quarter 2006, compared with a recurring segment loss of $7.1 million in 2005.

The improvement in second-quarter 2006 recurring segment profit adjusted to remove the effect of mark-to-accounting reflects improved results from the power and gas portfolios and lower miscellaneous expenses. The gas portfolio results include a benefit from monetizing certain forward basis positions, partially offset by realized losses on the natural gas storage portfolio that are expected to be recovered in 2007 when the inventory is sold.

YTD Power Recurring Segment Profit (Loss) Adjusted for Mark-to-Market Effect


	YTD '06			YTD '05
	(millions)			(millions)
Segment profit (loss)	$	(102.1	)	$	39.1
Nonrecurring adjustments	$	0.0		$	24.5

Recurring segment profit (loss)	$	(102.1	)	$	63.6
Mark-to-market adjustments — net	$	172.5		$	(53.3	)

Recurring segment profit after mark-to-market adjustments	$	70.4		$	10.3

For the first six months of 2006, Power reported a segment loss of $102.1 million compared with segment profit of $39.1 million for the first half of 2005. That change is primarily the result of lower forward unrealized mark-to-market earnings this year, partially offset by higher realized accrual portfolio results.

Williams — 2^nd Quarter Results — Aug. 3, 2006 — Page 9 of 12

The 2006 period includes forward unrealized mark-to-market gains of $4.4 million, compared with forward unrealized mark-to-market gains of $243.2 million in the first half of 2005. In first-quarter 2005, there were a significant number of contracts that had not yet been designated as FAS133 hedges, which incurred significant mark-to-market gains. The year-over-year variance resulted from fewer nondesignated contracts subject to mark-to-market accounting in 2006.

For the first six months of 2006, Power reported a recurring segment profit on a basis to remove the effect of mark-to-market accounting of $70.4 million, compared with $10.3 million for the first half of 2005. The increase in the first half of 2006 is primarily because of the improved power and gas portfolio results previously mentioned, as well as lower expenses from the positive effect of a $23.7 million gain on the sale of certain third-party receivables in the first quarter.

For 2006, Williams now expects a $150 million to $200 million segment loss from Power, which includes year-to-date unrealized mark-to-market earnings on derivative contracts but assumes no future change in fair value on these contracts. Williams previously expected a $105 million to $205 million loss in Power.

Williams expects Power to generate 2006 recurring segment profit of $75 million to $125 million after removing the effect of mark-to-market accounting. The company’s prior guidance from May for this measure was $50 million to $150 million.

Cash and Debt

At the close of business on June 30, 2006, Williams maintained total liquidity consisting of approximately $1.7 billion in unused and available revolving credit facilities; $980 million in unrestricted cash and cash equivalents; and approximately $400 million in other liquid investments. The unrestricted cash and cash equivalents includes $478 million in subsidiary cash, international cash and customer margin deposits.

During the second quarter, Williams retired $489 million of secured debt. The company has now retired or replaced all of its secured debt, with the exception of non-recourse project debt at its Venezuelan operations.

At June 30, Williams’ total outstanding debt was approximately $7.5 billion. Overall, the company has reduced its debt during the first half of 2006 by approximately $250 million on a net basis.

As Williams continues to support its planned capital investments during 2006, the company expects to conclude the year at a debt level that is comparable to or slightly greater than year-end 2005.

For the first half of 2006, net cash provided by operating activities was $673.3 million, compared with $793.3 million for the first half of 2005. Net cash this year is primarily being reinvested in capital expenditures. Williams made approximately $1 billion in capital expenditures in the first half this year.

Williams — 2^nd Quarter Results — Aug. 3, 2006 — Page 10 of 12

Today’s Analyst Call

Williams’ management will discuss the company’s second-quarter 2006 financial results and outlook 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) 810-0924. International callers should dial (913) 981-4900. Callers should dial in at least 10 minutes prior to the start of the discussion.

Replays of the second-quarter webcast will be available for two weeks at www.williams.com.

Form 10-Q

The company is filing its Form 10-Q this week with the Securities and Exchange Commission. 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

# # #

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

Williams — 2^nd Quarter Results — Aug. 3, 2006 — Page 11 of 12

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 annual report on Form 10-K filed with the Securities and Exchange Commission on March 9, 2006, and our quarterly reports on Form 10-Q available from our offices or from our website at www.williams.com.

Williams — 2^nd Quarter Results — Aug. 3, 2006 — Page 12 of 12

Financial Highlights and Operating Statistics

(UNAUDITED)

Final

June 30, 2006

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

(UNAUDITED)


	2005															2006
(Dollars in millions, except per-share amounts)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			Year

Income (loss) from continuing operations available to common stockholders	$	202.2		$	40.7		$	5.7		$	68.8		$	317.4		$	131.1			($63.9	)	$	67.2


Income (loss) from continuing operations — diluted earnings (loss) per common share	$	0.34		$	0.07		$	0.01		$	0.11		$	0.53		$	0.22			($0.11	)	$	0.11


Nonrecurring items:

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

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

Gas Pipeline
Prior period liability corrections — TGPL		(13.1	)		(4.6	)		—			—			(17.7	)		—			—			—
Prior period pension adjustment — TGPL		—			(17.1	)		—			—			(17.1	)		—			—			—
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			—			—			—
Reversal of litigation contigency due to favorable ruling — TGPL		—			—			—			—			—			(2.0	)		—			(2.0	)

Total Gas Pipeline nonrecurring items		(13.1	)		(21.7	)		(14.2	)		37.3			(11.7	)		(2.0	)		—			(2.0	)

Midstream Gas & Liquids
Accrual for Gulf Liquids litigation contingency		—			—			—			—			—			—			68.0			68.0
Settlement of an international contract dispute		—			—			—			—			—			(6.3	)		—			(6.3	)

Total Midstream Gas & Liquids nonrecurring items		—			—			—			—			—			(6.3	)		68.0			61.7

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			—			—			—

Other
Impairment of Longhorn		—			49.1			—			38.1			87.2			—			—			—
Write-off of capitalized project development costs		—			4.0			—			—			4.0			—			—			—
Gain on sale of real property		—			—			—			(9.0	)		(9.0	)		—			—			—

Total Other nonrecurring items		—			53.1			—			29.1			82.2			—			—			—

Nonrecurring items included in segment profit (loss)		(9.3	)		44.5			(35.5	)		158.1			157.8			(8.3	)		68.0			59.7

Nonrecurring items below segment profit (loss)
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)		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			—			—			—
Securities litigation settlement and related costs ⁽¹⁾		—			—			—			9.4			9.4			1.2			160.7			161.9
Reversal of interest accrual related to reversal of litigation contingency noted above (Interest accrued — Gas Pipeline — TGPL)		—			—			—			—			—			(5.0	)		—			(5.0	)
Early debt retirement costs (Corporate and Exploration & Production)		—			—			—			—			—			27.0	(1)		4.4			31.4
Gain on sale of Algar/Triangulo shares (Investing income / loss — Other)		—			—			—			—			—			(6.7	)		—			(6.7	)
Interest related to Gulf Liquids litigation contingency ( Interest accrued — Midstream)		—			—			—			—			—			—			20.0			20.0

		2.7			(8.6	)		18.8			9.4			22.3			16.5			185.1			201.6

Total nonrecurring items		(6.6	)		35.9			(16.7	)		167.5			180.1			8.2			253.1			261.3
Tax effect for above items ⁽¹⁾		(2.8	)		10.7			(6.4	)		48.0			49.5			3.4			76.6			80.0
Adjustment for nonrecurring excess deferred tax benefit		—			—			—			(20.2	)		(20.2	)		—			—			—


Recurring income (loss) from continuing operations available to common stockholders	$	198.4		$	65.9			($4.6	)	$	168.1		$	427.8		$	135.9		$	112.6		$	248.5


Recurring diluted earnings (loss) per common share	$	0.33		$	0.11			($0.01	)	$	0.28		$	0.72		$	0.23		$	0.19		$	0.42


Weighted-average shares — diluted (thousands)		599,422			578,902			580,735			609,106			605,847			607,073			595,561			598,634

⁽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. The tax rate applied to Midstream’s international contract dispute settlement in 1st quarter 2006 is 34%. The tax rate applied to nonrecurring items for 2nd quarter 2006 has been adjusted for the effect of nondeductible expenses associated with securities litigation settlement and related costs and early debt retirement costs related to our convertible debt.

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.

Consolidated Statement of Operations
(UNAUDITED)


	2005															2006
(Dollars in millions, except per-share amounts)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			Year


Revenues	$	2,954.0		$	2,871.2		$	3,082.3		$	3,676.1		$	12,583.6		$	3,027.5		$	2,715.1		$	5,742.6

Segment costs and expenses:
Costs and operating expenses		2,390.3			2,491.6			2,826.2			3,162.9			10,871.0			2,588.7			2,273.8			4,862.5
Selling, general and administrative expenses		73.5			62.7			90.6			98.6			325.4			71.0			109.3			180.3
Other (income) expense — net		(1.8	)		21.9			(21.4	)		62.5			61.2			(22.3	)		61.7			39.4

Total segment costs and expenses		2,462.0			2,576.2			2,895.4			3,324.0			11,257.6			2,637.4			2,444.8			5,082.2


Equity earnings		17.7			9.8			17.6			20.5			65.6			22.2			23.1			45.3
Loss from investments		—			(48.4	)		—			(60.7	)		(109.1	)		—			(0.5	)		(0.5	)

Total segment profit		509.7			256.4			204.5			311.9			1,282.5			412.3			292.9			705.2


Reclass equity earnings		(17.7	)		(9.8	)		(17.6	)		(20.5	)		(65.6	)		(22.2	)		(23.1	)		(45.3	)
Reclass loss from investments		—			48.4			—			60.7			109.1			—			0.5			0.5
General corporate expenses		(28.0	)		(35.5	)		(42.8	)		(48.6	)		(154.9	)		(30.6	)		(33.7	)		(64.3	)
Securities litigation settlement and related fees		—			—			—			—			—			(1.2	)		(160.7	)		(161.9	)


Operating income		464.0			259.5			144.1			303.5			1,171.1			358.3			75.9			434.2

Interest accrued		(164.7	)		(164.6	)		(166.0	)		(176.4	)		(671.7	)		(162.8	)		(181.5	)		(344.3	)
Interest capitalized		1.1			1.4			1.8			2.9			7.2			3.0			4.0			7.0
Investing income (loss)		31.0			(17.2	)		31.1			(21.2	)		23.7			46.9			43.3			90.2
Early debt retirement costs		—			—			—			(0.4	)		(0.4	)		(27.0	)		(4.4	)		(31.4	)
Minority interest in income of consolidated subsidiaries		(5.2	)		(4.8	)		(6.8	)		(8.9	)		(25.7	)		(7.1	)		(8.3	)		(15.4	)
Other income (expense) — net		5.5			8.1			(1.1	)		14.6			27.1			8.1			8.0			16.1


Income (loss) from continuing operations before income taxes and cumulative effect of change in accounting principle		331.7			82.4			3.1			114.1			531.3			219.4			(63.0	)		156.4

Provision (benefit) for income taxes		129.5			41.7			(2.6	)		45.3			213.9			88.3			0.9			89.2


Income (loss) from continuing operations		202.2			40.7			5.7			68.8			317.4			131.1			(63.9	)		67.2

Income (loss) from discontinued operations		(1.1	)		0.6			(1.3	)		(0.3	)		(2.1	)		0.8			(12.1	)		(11.3	)


Income before cumulative effect of change in accounting principle		201.1			41.3			4.4			68.5			315.3			131.9			(76.0	)		55.9
Cumulative effect of change in accounting principle		—			—			—			(1.7	)		(1.7	)		—			—			—


Net income (loss)	$	201.1		$	41.3		$	4.4		$	66.8		$	313.6		$	131.9		$	(76.0	)	$	55.9


Diluted earnings per common share:

Income (loss) from continuing operations	$	0.34		$	0.07		$	0.01		$	0.11		$	0.53		$	0.22		$	(0.11	)	$	0.11

Income (loss) from discontinued operations		—			—			—			—			—			—			(0.02	)		(0.02	)


Income before cumulative effect of change in accounting principle		0.34			0.07			0.01			0.11			0.53			0.22			(0.13	)		0.09

Cumulative effect of change in accounting principle		—			—			—			—			—			—			—			—


Net income (loss)	$	0.34		$	0.07		$	0.01		$	0.11		$	0.53		$	0.22		$	(0.13	)	$	0.09


Weighted-average number of shares used in computation (thousands)		599,422			578,902			580,735			609,106			605,847			607,073			595,561			598,634

Common shares outstanding at end of period (thousands)		570,501			571,502			572,922			573,592			573,592			595,007			595,562			595,562

Market price per common share (end of period)	$	18.81		$	19.00		$	25.05		$	23.17		$	23.17		$	21.39		$	23.36		$	23.36

Common dividends per share	$	0.05		$	0.05		$	0.075		$	0.075		$	0.25		$	0.075		$	0.09		$	0.165


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. Certain amounts have been reclassified to conform to current classifications.

Reconciliation of Segment Profit to Recurring Segment Profit
(UNAUDITED)


	2005															2006
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			Year


Segment profit (loss):

Exploration & Production	$	103.7		$	118.3		$	158.8		$	206.4		$	587.2		$	147.6		$	119.8		$	267.4
Gas Pipeline		167.4			164.5			161.1			92.8			585.8			134.7			122.7			257.4
Midstream Gas & Liquids		128.6			109.1			121.1			112.4			471.2			151.5			130.7			282.2
Power		114.1			(75.0	)		(226.4	)		(69.4	)		(256.7	)		(22.5	)		(79.6	)		(102.1	)
Other		(4.1	)		(60.5	)		(10.1	)		(30.3	)		(105.0	)		1.0			(0.7	)		0.3

Total segment profit	$	509.7		$	256.4		$	204.5		$	311.9		$	1,282.5		$	412.3		$	292.9		$	705.2


Nonrecurring adjustments:

Exploration & Production	$	(7.6	)	$	—		$	(21.7	)	$	—		$	(29.3	)	$	—		$	—		$	—
Gas Pipeline		(13.1	)		(21.7	)		(14.2	)		37.3			(11.7	)		(2.0	)		—			(2.0	)
Midstream Gas & Liquids		—			—			—			—			—			(6.3	)		68.0			61.7
Power		11.4			13.1			0.4			91.7			116.6			—			—			—
Other		—			53.1			—			29.1			82.2			—			—			—

Total segment nonrecurring adjustments	$	(9.3	)	$	44.5		$	(35.5	)	$	158.1		$	157.8		$	(8.3	)	$	68.0		$	59.7


Recurring segment profit (loss):

Exploration & Production		96.1			118.3			137.1			206.4			557.9			147.6			119.8			267.4
Gas Pipeline		154.3			142.8			146.9			130.1			574.1			132.7			122.7			255.4
Midstream Gas & Liquids		128.6			109.1			121.1			112.4			471.2			145.2			198.7			343.9
Power		125.5			(61.9	)		(226.0	)		22.3			(140.1	)		(22.5	)		(79.6	)		(102.1	)
Other		(4.1	)		(7.4	)		(10.1	)		(1.2	)		(22.8	)		1.0			(0.7	)		0.3

Total recurring segment profit	$	500.4		$	300.9		$	169.0		$	470.0		$	1,440.3		$	404.0		$	360.9		$	764.9


Note:		Segment profit (loss) includes equity earnings (loss) and certain income (loss) from investments reported in Investing income (loss) in the Consolidated Statement of Operations. Equity earnings (loss) results from investments accounted for under the equity method. Income (loss) from investments results from the management of certain equity investments.

Exploration & Production
(UNAUDITED)


	2005															2006
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			Year


Revenues:
Production	$	210.2		$	234.8		$	283.0		$	344.4		$	1,072.4		$	286.8		$	287.9		$	574.7
Gas management		28.2			32.6			32.1			52.0			144.9			41.2			28.3			69.5
Net nonqualified hedge derivative income (loss)		(0.1	)		0.6			(15.9	)		9.8			(5.6	)		12.8			(1.6	)		11.2
International		10.8			11.6			16.3			14.7			53.4			16.0			15.1			31.1
Other		(0.1	)		1.9			2.9			(0.7	)		4.0			(0.8	)		12.6			11.8

Total revenues		249.0			281.5			318.4			420.2			1,269.1			356.0			342.3			698.3

Segment costs and expenses:
Depreciation, depletion and amortization (including International)		58.5			59.5			66.4			69.6			254.0			73.1			84.5			157.6
Lease and other operating expenses *		23.8			23.9			28.5			29.0			105.2			30.1			43.8			73.9
Operating taxes		21.1			23.9			26.7			29.4			101.1			31.8			28.1			59.9
Exploration expenses *		0.9			1.1			1.5			4.1			7.6			4.4			2.4			6.8
Gathering expense		5.6			6.0			5.0			8.1			24.7			6.4			7.5			13.9
Selling, general and administrative expenses (including International)		17.0			17.7			20.3			24.6			79.6			21.5			28.2			49.7
Gas management expenses		28.2			32.6			32.1			52.0			144.9			41.2			28.3			69.5
International (excluding DD&A and SG&A)		3.3			3.3			4.7			3.6			14.9			5.5			4.9			10.4
Other (income) expense — net		(9.6	)		(1.2	)		(19.8	)		(0.7	)		(31.3	)		(0.6	)		0.7			0.1

Total segment costs and expenses		148.8			166.8			165.4			219.7			700.7			213.4			228.4			441.8

Equity earnings — International		3.5			3.6			5.8			5.9			18.8			5.0			5.9			10.9


Reported segment profit		103.7			118.3			158.8			206.4			587.2			147.6			119.8			267.4

Nonrecurring adjustments		(7.6	)		—			(21.7	)		—			(29.3	)		—			—			—


Recurring segment profit, pre-tax	$	96.1		$	118.3		$	137.1		$	206.4		$	557.9		$	147.6		$	119.8		$	267.4

* Amounts have been reclassified to the current classifications.

Operating statistics

Domestic:
Total domestic net volumes (Bcfe)		51.1			55.0			57.9			59.5			223.5			59.5			67.1			126.6
Net domestic volumes per day (MMcfe/d)		568			604			629			646			612			661			738			700
Net domestic realized price ($/Mcfe) (1)	$	4.001		$	4.164		$	4.801		$	5.655		$	4.688		$	4.712		$	4.177		$	4.428
Production taxes per Mcfe	$	0.413		$	0.435		$	0.462		$	0.493		$	0.452		$	0.534		$	0.420		$	0.473
Lease and other operating expense per Mcfe	$	0.466		$	0.436		$	0.492		$	0.486		$	0.471		$	0.505		$	0.653		$	0.584

(1) Net realized price is calculated the following way: production revenues (including hedging activities and incremental margins related to gas management activities) divided by net volumes.


International:
Total volumes including Equity Investee (Bcfe)	5.3	5.5	6.1	6.0	22.9	6.0	5.6	11.6
Volumes per day (MMcfe/d)	59	61	67	65	63	67	61	64

Volumes net to Williams (after minority interest) (Bcfe)	4.1	4.3	4.8	4.8	18.0	4.7	4.4	9.1
Volumes net to Williams per day (MMcfe/d)	46	48	53	51	49	53	48	50

Total Domestic and International:
Volumes net to Williams (after minority interest) (Bcfe)	55.3	59.3	62.7	64.2	241.5	64.2	71.5	135.7
Volumes net to Williams per day (MMcfe/d)	614	652	682	697	662	714	786	750

Gas Pipeline
(UNAUDITED)


	2005														2006
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr		Year			1st Qtr			2nd Qtr			Year


Revenues:
Northwest Pipeline	$	80.3		$	78.9		$	79.6		$	82.7	$	321.5		$	79.6		$	80.0		$	159.6
Transcontinental Gas Pipe Line		254.9			278.1			266.0			292.0		1,091.0			254.3			257.2			511.5
Other		0.1			—			0.2			—		0.3			0.1			0.1			0.2

Total revenues		335.3			357.0			345.8			374.7		1,412.8			334.0			337.3			671.3

Segment costs and expenses:
Costs and operating expenses		160.4			193.3			177.6			250.7		782.0			177.2			192.8			370.0
Selling, general and administrative expenses		18.6			6.8			23.6			35.1		84.1			31.0			35.4			66.4
Other (income) expense — net		0.3			0.3			0.5			3.4		4.5			(1.4	)		(3.4	)		(4.8	)

Total segment costs and expenses		179.3			200.4			201.7			289.2		870.6			206.8			224.8			431.6

Equity earnings		11.4			7.9			17.0			7.3		43.6			7.5			10.7			18.2
Income (loss) from investments		—			—			—			—		—			—			(0.5	)		(0.5	)


Reported segment profit:
Northwest Pipeline		39.7			36.5			39.1			37.2		152.5			33.3			32.8			66.1
Transcontinental Gas Pipe Line		117.9			121.8			107.0			50.1		396.8			95.8			81.3			177.1
Other		9.8			6.2			15.0			5.5		36.5			5.6			8.6			14.2

Total reported segment profit		167.4			164.5			161.1			92.8		585.8			134.7			122.7			257.4

Nonrecurring adjustments:
Northwest Pipeline		—			—			—			—		—			—			—			—
Transcontinental Gas Pipe Line		(13.1	)		(21.7	)		(14.2	)		37.3		(11.7	)		(2.0	)		—			(2.0	)
Other		—			—			—			—		—			—			—			—

Total nonrecurring adjustments		(13.1	)		(21.7	)		(14.2	)		37.3		(11.7	)		(2.0	)		—			(2.0	)

Recurring segment profit:
Northwest Pipeline		39.7			36.5			39.1			37.2		152.5			33.3			32.8			66.1
Transcontinental Gas Pipe Line		104.8			100.1			92.8			87.4		385.1			93.8			81.3			175.1
Other		9.8			6.2			15.0			5.5		36.5			5.6			8.6			14.2

Total recurring segment profit, pre-tax	$	154.3		$	142.8		$	146.9		$	130.1	$	574.1		$	132.7		$	122.7		$	255.4

Operating statistics

Northwest Pipeline
Throughput (TBtu)		181.2			146.2			152.9			192.6		672.9			179.7			142.7			322.4
Average daily transportation volumes (TBtu)		2.0			1.6			1.7			2.1		1.9			2.0			1.6			1.8
Average daily firm reserved capacity (TBtu)		2.5			2.5			2.5			2.5		2.5			2.5			2.5			2.5

Transcontinental Gas Pipe Line
Throughput (TBtu)		537.7			427.9			453.6			466.6		1,885.8			502.8			427.0			929.8
Average daily transportation volumes (TBtu)		6.0			4.7			4.9			5.1		5.2			5.6			4.6			5.1
Average daily firm reserved capacity (TBtu)		6.9			6.5			6.4			6.8		6.7			7.0			6.4			6.7


Midstream Gas & Liquids (UNAUDITED)


	2005															2006
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			Year

Revenues:
Gathering	$	70.6		$	74.2		$	74.0		$	75.8		$	294.6		$	76.8		$	79.0		$	155.8
Processing		23.5			24.3			25.5			22.9			96.2			24.9			27.4			52.3
Venezuela fee revenue		36.5			37.8			40.4			38.8			153.5			38.9			38.0			76.9
NGL sales from gas processing		285.1			247.0			244.2			259.0			1,035.3			263.7			292.6			556.3
Production handling and transportation		18.6			20.4			14.7			20.6			74.3			37.2			33.2			70.4
Olefins sales (Incl Gulf and Canada)		146.6			114.2			121.4			185.3			567.5			148.9			131.4			280.3
Trading/marketing sales		588.0			574.4			522.0			578.1			2,262.5			709.0			806.1			1,515.1
Other revenues		23.7			33.2			31.7			39.1			127.7			34.4			30.7			65.1

		1,192.6			1,125.5			1,073.9			1,219.6			4,611.6			1,333.8			1,438.4			2,772.2

Intrasegment eliminations		(385.6	)		(345.4	)		(319.2	)		(328.7	)		(1,378.9	)		(354.4	)		(394.9	)		(749.3	)

Total revenues		807.0			780.1			754.7			890.9			3,232.7			979.4			1,043.5			2,022.9
Segment costs and expenses:
NGL cost of goods sold		225.1			202.4			189.6			218.3			835.4			199.9			172.7			372.6
Olefins cost of goods sold		118.7			104.0			102.2			163.5			488.4			132.8			108.1			240.9
Trading/marketing cost of goods sold		584.0			574.7			510.1			575.8			2,244.6			716.7			799.1			1,515.8
Venezuela operating costs		16.1			16.0			17.4			17.6			67.1			16.8			18.1			34.9
Operating costs		101.6			101.5			112.8			113.9			429.8			120.6			120.7			241.3
Other
Selling, general and administrative expenses		22.9			21.0			23.1			29.3			96.3			23.3			25.2			48.5
Other (income) expense — net		2.6			1.7			0.8			(1.7	)		3.4			(17.9	)		70.0			52.1
Intrasegment eliminations		(385.5	)		(345.5	)		(319.2	)		(328.7	)		(1,378.9	)		(354.4	)		(394.9	)		(749.3	)

Total segment costs and expenses		685.5			675.8			636.8			788.0			2,786.1			837.8			919.0			1,756.8
Equity earnings		7.1			4.1			3.2			9.2			23.6			9.9			6.2			16.1
Income from investments		—			0.7			—			0.3			1.0			—						—

Reported segment profit		128.6			109.1			121.1			112.4			471.2			151.5			130.7			282.2
Nonrecurring adjustments		—			—			—			—			—			(6.3	)		68.0			61.7

Recurring segment profit, pre-tax	$	128.6		$	109.1		$	121.1		$	112.4		$	471.2		$	145.2		$	198.7		$	343.9


Operating statistics

Gathering volumes (TBtu)		315.5			323.6			310.3			303.9			1,253.3			296.9			300.1			597.0
Gathering margins ($/MMBtu)	$	0.2237		$	0.2292		$	0.2386		$	0.2496		$	0.2351		$	0.2590		$	0.2634		$	0.2610

Processing volumes (TBtu)		181.0			184.5			190.3			165.6			721.4			191.8			204.8			396.6
Processing rate ($/MMBtu)	$	0.1299		$	0.1316		$	0.1342		$	0.1381		$	0.1334		$	0.1298		$	0.1340		$	0.1320

NGL equity sales (million gallons)		398.7			338.3			276.4			255.8			1,269.2			333.7			361.3			695.0
NGL margin ($/gallon)	$	0.1503		$	0.1318		$	0.1976		$	0.1565		$	0.1569		$	0.1900		$	0.3319		$	0.2644

Olefins sales (Ethylene & Propylene) (million lbs)		266.5			265.6			258.1			275.9			1,066.1			259.2			196.8			456.0

Power
(UNAUDITED)


	2005															2006
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			Year


Revenues:
Natural gas & power	$	2,066.3		$	1,998.6		$	2,244.3		$	2,787.0		$	9,096.2		$	2,053.3		$	1,606.6		$	3,659.9
Crude & refined products		(1.1	)		(0.2	)		(1.6	)		0.1			(2.8	)		—			—			—
Other		(0.3	)		1.0			0.2			(0.4	)		0.5			(0.1	)		0.4			0.3

Total revenues		2,064.9			1,999.4			2,242.9			2,786.7		$	9,093.9			2,053.2			1,607.0		$	3,660.2

Segment costs and expenses:
Costs and operating expenses		1,930.3			2,041.1			2,450.9			2,750.2			9,172.5			2,082.1			1,671.4			3,753.5
Selling, general and administrative expenses		16.0			16.9			21.1			10.5			64.5			(4.5	)		18.9			14.4
Other (income) expense — net		5.6			17.3			(1.7	)		95.5			116.7			(2.1	)		(3.4	)		(5.5	)

Total segment costs and expenses		1,951.9			2,075.3			2,470.3			2,856.2			9,353.7			2,075.5			1,686.9			3,762.4

Equity Earnings		1.1			0.9			1.0			0.1			3.1			(0.2	)		0.3			0.1


Reported segment profit (loss)		114.1			(75.0	)		(226.4	)		(69.4	)		(256.7	)		(22.5	)		(79.6	)		(102.1	)

Nonrecurring adjustments		11.4			13.1			0.4			91.7			116.6			—			—			—


Recurring segment profit (loss), pre-tax	$	125.5		$	(61.9	)	$	(226.0	)	$	22.3		$	(140.1	)	$	(22.5	)	$	(79.6	)	$	(102.1	)

Operating statistics

Volumes
Natural gas (Bcfd)
Sales to third parties		1.7			1.8			1.7			1.7			1.7			1.7			1.5			1.6
Sales to other segments		0.6			0.4			0.3			0.3			0.4			0.4			0.4			0.4
For use in tolling agreements and by owned generation		0.2			0.2			0.3			0.1			0.2			0.1			0.2			0.2

Total managed		2.5			2.4			2.3			2.1			2.3			2.2			2.1			2.2
Crude & refined products (MBPD)		—			—			—			—			—			—			—			—
Power (GWh)		14,832			15,906			21,690			14,559			66,987			11,505			12,949			24,454

Additional statistics

Value at risk


		Quarter ended 6/30/2006
One day VaR - 95% confidence level		(in Millions)
Trading		$3.1MM
Non-Trading		$24.9MM
Aggregate Earnings VaR		$5.6MM


		Quarter ended 3/31/2006
One day VaR - 95% confidence level		(in Millions)
Trading		$3.8MM
Non-Trading		$6.0MM
Aggregate Earnings VaR		$9.2MM


Net Credit Exposure (in Millions)	Investment
	Grade		Total
Gas and electric utilities	$	96.6	$	96.9
Energy marketers and traders		238.9		557.2
Financial institutions		31.2		31.2
Other		25.3		25.3

	$	392.0	$	710.6

Credit Reserves				(22.8	)

Net Credit Exposure from Derivative Contracts			$	687.8

Fair Value Of Mark-to-Market Derivatives (in Millions)

Period the value of mark-to-market derivatives is expected to be realized:


1-12 months	$	18.7
13-36 months		(0.3	)
37-60 months		(0.4	)
61-120 months		(0.6	)
121+ months		0.1

Total Fair Value		17.5

Non-Trading MTM Derivatives and SFAS 133 Hedges		291.8
Non-Power Business Unit Hedges		1.9

Total Net Derivative Assets and Liabilities	$	311.2


Power Portfolio	Quarter Ended
(Megawatts)	6/30/06		6/30/05

Owned		207		207
Contracted		8,190		9,012

Total		8,397		9,219

Credit Support (in Millions)


As of June 30, 2006
Prepays	$	11

Margins	$	0

Adequate Assurance	$	18

Capital Expenditures and Investments
(UNAUDITED)


	2005											2006
(Dollars in millions)	1st Qtr			2nd Qtr		3rd Qtr		4th Qtr		Year		1st Qtr			2nd Qtr		Year


Capital expenditures:
Exploration & Production	$	158.6		$	182.8	$	211.1	$	230.8	$	783.3	$	310.3		$	283.9	$	594.2

Gas Pipeline:
Northwest Pipeline		12.0			29.6		43.2		52.2		137.0		40.3			96.0		136.3
Transcontinental Gas Pipe Line		35.7			55.0		80.7		83.1		254.5		46.4			106.7		153.1
Other		—			—		—		2.2		2.2		—			—		—

Total		47.7			84.6		123.9		137.5		393.7		86.7			202.7		289.4

Midstream Gas & Liquids		16.3			25.5		32.7		40.7		115.2		70.7			39.3		110.0
Power		1.0			0.7		0.4		0.1		2.2		0.6			0.6		1.2
Other		(0.7	)*		0.1		1.2		4.0		4.6		—			7.8		7.8

Total	$	222.9		$	293.7	$	369.3	$	413.1	$	1,299.0	$	468.3		$	534.3	$	1,002.6


Purchase of investments:
Exploration & Production	$	6.3		$	—	$	0.3	$	—	$	6.6	$	—		$	—	$	—
Midstream Gas & Liquids		—			35.0		11.5		—		46.5		(3.4	)		0.8		(2.6	)
Other		20.0			20.6		4.5		17.9		63.0		13.1			26.0		39.1

Total	$	26.3		$	55.6	$	16.3	$	17.9	$	116.1	$	9.7		$	26.8	$	36.5


Summary:
Exploration & Production	$	164.9		$	182.8	$	211.4	$	230.8	$	789.9	$	310.3		$	283.9	$	594.2
Gas Pipeline		47.7			84.6		123.9		137.5		393.7		86.7			202.7		289.4
Midstream Gas & Liquids		16.3			60.5		44.2		40.7		161.7		67.3			40.1		107.4
Power		1.0			0.7		0.4		0.1		2.2		0.6			0.6		1.2
Other		19.3			20.7		5.7		21.9		67.6		13.1			33.8		46.9

Total	$	249.2		$	349.3	$	385.6	$	431.0	$	1,415.1	$	478.0		$	561.1	$	1,039.1


Cumulative summary:
Exploration & Production	$	164.9		$	347.7	$	559.1	$	789.9	$	789.9	$	310.3		$	594.2	$	594.2
Gas Pipeline		47.7			132.3		256.2		393.7		393.7		86.7			289.4		289.4
Midstream Gas & Liquids		16.3			76.8		121.0		161.7		161.7		67.3			107.4		107.4
Power		1.0			1.7		2.1		2.2		2.2		0.6			1.2		1.2
Other		19.3			40.0		45.7		67.6		67.6		13.1			46.9		46.9

Total	$	249.2		$	598.5	$	984.1	$	1,415.1	$	1,415.1	$	478.0		$	1,039.1	$	1,039.1


*		Reflects the transfer of property from the corporate parent to various segments.

Depreciation, Depletion and Amortization and Other Selected Financial Data
(UNAUDITED)


	2005															2006
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			Year


Depreciation, depletion and amortization:
Exploration & Production	$	58.6		$	59.4		$	66.4		$	69.8		$	254.2		$	73.0			84.2			157.2
Gas Pipeline:
Northwest Pipeline		17.3			17.0			17.9			18.4			70.6			18.5			18.8			37.3
Transcontinental Gas Pipe Line		49.4			48.6			49.3			49.4			196.7			50.0			51.7			101.7

Total		66.7			65.6			67.2			67.8			267.3			68.5			70.5			139.0
Midstream Gas & Liquids		46.0			46.4			49.5			50.1			192.0			49.4			49.9			99.3
Power		3.9			3.7			3.6			3.7			14.9			3.2			3.2			6.4
Other		3.0			3.0			2.9			2.7			11.6			2.9			2.7			5.6

Total	$	178.2		$	178.1		$	189.6		$	194.1		$	740.0		$	197.0		$	210.5		$	407.5


Other selected financial data:
Cash and cash equivalents	$	1,210.0		$	1,297.2		$	1,360.5		$	1,597.2		$	1,597.2		$	1,115.0		$	980.4		$	980.4

Total assets	$	26,434.1		$	26,399.7		$	33,655.8		$	29,442.6		$	29,442.6		$	26,029.0		$	25,617.2		$	25,617.2

Capital structure:
Debt
Current	$	99.5		$	98.6		$	122.4		$	122.6		$	122.6		$	175.7		$	170.7		$	170.7
Noncurrent	$	7,650.4		$	7,645.7		$	7,598.7		$	7,590.5		$	7,590.5		$	7,252.8		$	7,292.6		$	7,292.6
Stockholders’ equity	$	5,261.1		$	5,353.6		$	5,154.4		$	5,427.5		$	5,427.5		$	5,925.5		$	5,882.3		$	5,882.3
Debt to debt-plus-equity ratio		59.6	%		59.1	%		60.0	%		58.7	%		58.7	%		55.6	%		55.9	%		55.9	%

Adjustment to remove MTM effect

Dollars in millions except for per share amounts


	2006										2005
	1Q			2Q		3Q	4Q	Year			1Q			2Q			3Q			4Q			Year

Recurring income from cont. ops available to common shareholders	$	136		$	113			$	249		$	198		$	66		$	(5	)	$	168		$	428
Recurring diluted earnings per common share	$	0.23		$	0.19			$	0.42		$	0.33		$	0.11		$	(0.01	)	$	0.28		$	0.72
Mark-to-Market (MTM) adjustments:
Reverse forward unrealized MTM gains/losses		(43	)		38				(5	)		(221	)		(22	)		141			(70	)		(172	)
Add realized gains/losses from MTM previously recognized		77			100				177			113			77			72			48			310

Total MTM adjustments		34			138				172			(108	)		55			213			(22	)		138
Tax effect of total MTM adjustments (at 39%)		13			53				66			(42	)		21			83			(8	)		53

After tax MTM adjustments		21			85				106			(66	)		34			130			(14	)		85
Recurring income from cont. ops available to common shareholders after MTM adjust.	$	157		$	198			$	355		$	132		$	100		$	125		$	154		$	513
Recurring diluted earnings per share after MTM adj.	$	0.26		$	0.33			$	0.59		$	0.22		$	0.17		$	0.22		$	0.26		$	0.86
weighted average shares — diluted (thousands)		607,073			595,561				598,634			599,422			578,902			580,735			609,106			605,847

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

Non-GAAP Utility Statement:

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

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

exv99w2

Exhibit 99.2

Williams 2006 2nd Quarter Earnings August 3, 2006

Forward Looking Statements 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

Oil and 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.

Overview Steve Malcolm Chairman, President & CEO

Headlines Execution of strategy delivers very strong 2Q Nearly DOUBLED recurring income after removing mark-to-market effect Raising profit guidance for '06, '07 and '08 19% jump up in guidance for '06 key earnings measure* Boosting planned capital expenditures to develop reserves MLP strategy to accelerate delivery of benefits to Williams *Recurring income from continuing operations after mark-to-market adjustment

Executing on our strategy to drive near- and long-term value creation Delivering on our promises. So far in 2006, we have: Increased dividend 20% Increased natural gas production nearly 20% Completed $360 million drop-down into Williams Partners Resolved significant legacy issues Very strong 2Q results 99% higher recurring results after removing mark-to-market effect Posted nearly $200 million in Midstream recurring segment profit Robust NGL margins more than offset lower natural gas prices Well-positioned for continued success Increasing 2006-2008 profit guidance Boosting capital spending to develop reserves Accelerating MLP drop-downs

Well-positioned for continued success: Accelerating MLP drop-downs Pursuing growth with discipline and diligence Successful IPO in August 2005 Recently closed $360 million transaction - drop-down of 25.1% of Four Corners gathering and processing assets 21% increase in WPZ unit distribution level since IPO Strategy to accelerate delivery of MLP benefits to Williams Goal to drop down $1 billion to $1.5 billion in assets during next 6 months Deep bench of qualifying assets supports annual drop-downs of $1 billion to $2 billion during guidance period MLP strategy requires disciplined capital structure WPZ access to debt and equity capital markets is key source of funding to acquire drop-down assets WPZ's debt is consolidated on Williams' balance sheet and the partnership's credit rating is linked to Williams'

Key drivers for our MLP drop-downs Ongoing source of lower-cost capital WMB's general partnership interest grows in size, value Growing source of cash distributions from LP units and general partnership Some retained MLP units - cash distributions, value upside

Financial Results Don Chappel Chief Financial Officer

2006 2005 2006 2005 Income (Loss) from Continuing Operations ($64) $40 $67 $243 Income (Loss) from Discontinued Operations (12) 1 (11) (1) Net Income (Loss) ($76) $41 $56 $242 Net Income (Loss) /Share ($0.13) $0.07 $0.09 $0.41 Recurring Income from Continuing Ops./Share $0.19 $0.11 $0.42 $0.45 Recurring Income from Continuing Operations After MTM Adjustments/Share $0.33 $0.17 $0.59 $0.39 Financial Results Dollars in millions ( except per share amounts) Financial Results A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations after mark-to-market adjustments is available on Williams' Web site at www.williams.com and at the end of this presentation. 2nd Quarter YTD

2006 2005 2006 2005 Income (Loss) from Continuing Operations ($64) $40 $67 $243 Nonrecurring Items Regulatory & Litigation Contingencies/ Settlements and Related Costs 249 13 243 18 Debt Retirement Expense 4 - 31 - Impairments/Losses/Write-offs - 53 - 53 (Income)/expense related to prior periods - (22) (6) (28) Gain on sale of assets - (9) (7) (17) Other - Net - 1 1 3 Total Nonrecurring items before taxes 253 36 262 29 Tax effect of adjustments (76) (10) (80) (8) Recurring Inc. from Continuing Ops. Avail to Com. $113 $66 $249 $264 Recurring Income from Continuing Ops./Share $0.19 $0.11 $0.42 $0.45 Recurring Income from Continuing Operations Dollars in millions ( except per share amounts) Financial Results A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations after mark-to-market adjustments is available on Williams' Web site at www.williams.com and at the end of this presentation. 2nd Quarter YTD

2006 2005 2006 2005 Recurring Inc. from Cont. Ops. Avail. to Common $113 $66 $249 $264 Recurring Diluted Earnings per Common Share $0.19 $0.11 $0.42 $0.45 Mark-to-Market (MTM) adjustments for Power: Reverse forward unrealized MTM (gains)/losses $38 $(22) $(4) $(243) Add realized gains from MTM previously recognized 100 77 177 190 Total MTM Adjustments 138 55 173 (53) Tax Effect of Total MTM Adjustments (53) (21) (67) 21 After-Tax MTM Adjustments $85 $34 $106 $(32) Recurring Inc. from Cont. Ops. Avail. to Common Shareholders after MTM adjustments $198 $100 $355 $232 Recurring Diluted Earnings Per Share after MTM adjustments $0.33 $0.17 $0.59 $0.39 Recurring Income from Cont. Ops. After MTM Adjustment Dollars in millions ( except per share amounts) Financial Results Note: Adjustments have been made to reverse estimated forward unrealized mark-to-market ("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 mark-to-market adjustments is available on Williams' Web site at www.williams.com and at the end of this presentation. 2nd Quarter YTD

Second Quarter Segment Profit 2006 2005 2006 2005 Exploration & Production $120 $118 $120 $118 Midstream Gas & Liquids 131 109 199 109 Gas Pipeline 123 165 123 143 Power (80) (75) (80) (62) Other (1) (61) (1) (7) Segment Profit $293 $256 $361 $301 MTM Adjustments - Power 139 55 Segment Profit after MTM Adjustments $500 $356 Memo: Power after MTM Adjustments $59 ($7) Dollars in millions 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. Financial Results Reported Recurring

2006 2005 2006 2005 Exploration & Production $267 $222 $267 $214 Midstream Gas & Liquids 282 238 344 238 Gas Pipeline 257 332 255 297 Power (102) 39 (102) 64 Other 1 (65) 1 (12) Segment Profit $705 $766 $765 $801 MTM Adjustments - Power 173 (53) Segment Profit after MTM Adjustments $938 $748 Memo: Power after MTM Adjustments $71 $11 2006 YTD Segment Profit Dollars in millions 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. Financial Results Reported Recurring

2006 2005 2006 2005 Segment Profit $120 $118 $267 $222 Nonrecurring Gain on sale of assets - - - (8) Recurring segment profit $120 $118 $267 $214 Segment Profit - Exploration & Production 2Q06 to 2Q05 financial highlights: 20% volume production growth $50 million negative hedge impact in 2Q06 Operating expense up $0.21/Mfce, $0.09/Mcfe after adjustments for prior periods $0.05 of the $0.09/Mcfe due to production enhancement workover program Dollars in millions 2006 YTD to 2005 YTD financial highlights: 18.5% volume production growth 25% recurring segment profit growth $135MM negative hedge impact year to date Financial Results 2nd Quarter YTD

Segment Profit - Midstream 2Q06 to 2Q05 financial highlights: Record NGL unit margins Higher fee revenue Higher Canadian margins Increased operating expenses Financial Results 2006 YTD to 2005 YTD financial highlights: Higher NGL unit margins Higher fee revenue Increased operating expenses 2006 2005 2006 2005 Segment Profit $131 $109 $282 $238 Nonrecurring Accrual for Gulf Liquids litigation 68 - 68 - International Contract Settlement - - (6) - Recurring segment profit $199 $109 $344 $238 Dollars in millions 2nd Quarter YTD

2006 2005 2006 2005 Segment Profit $123 $165 $257 $332 Nonrecurring Excess royalty reserve reversal - - (2) - Pension expense reduction - (17) - (17) Adjustment to carrying value of certain liabilities - (5) - (18) Recurring segment profit $123 $143 $255 $297 Segment Profit - Gas Pipeline 2Q06 to 2Q05 financial highlights: Higher: operating expenses pension expense property insurance Partially offset by higher earnings of Gulfstream & other JVs Financial Results 2006 YTD to 2005 YTD financial highlights: 2006: Higher operating expenses & taxes 2005 recurring income associated with Gulfstream completion fee Operating tax adjustment Dollars in millions 2nd Quarter YTD

2006 2005 2006 2005 Segment Profit/(Loss) ($80) ($75) ($102) $39 Nonrecurring Accrual for regulatory & litigation Contingencies/Settlements - 13 - 17 Expense related to prior periods - - - 8 Recurring segment profit/(loss) (80) (62) (102) 64 MTM Adjustment (Recurring) 138 55 173 (53) Recurring segment profit/(loss) after MTM Adj. $59 ($7) $71 $11 Segment Profit - Power 2Q06 to 2Q05 financial highlights: Increase in hedged cash flows largely due to benefit of structured hedges and improved power market conditions Increase in natural gas results due to monetizing certain non-core basis positions, partially offset by losses on storage portfolio Dollars in millions 2006 YTD to 2005 YTD financial highlights: Increase in hedged cash flows largely due to benefit of structured hedges and improved power market conditions Decrease in expenses (including SG&A) includes $25 million gain related to sale of certain Enron receivables. Financial Results 2nd Quarter YTD

Liquidity at June 30, 2006 Financial Results Dollars in millions Cash and cash equivalents 980 $ Other current securities 405 Less: Subsidiary and Int'l cash & cash equivalents 446 $ Customer margin deposits payable 32 (478) Available unrestricted cash 907 Available revolver capacity 1,742 Total Liquidity 2,649 $

2006 Cash Information Financial Results Dollars in millions 2nd Quarter YTD Beginning Unrestricted Cash 1,115 $ 1,597 $ Cash flow from Continuing Operations 509 673 Debt retirements (664) (728) Proceeds from debt issuance 699 699 Proceeds from sale of limited partnership units 225 225 Capital expenditures (534) (1,003) Dividends (54) (98) Dividends to minority interests (10) (17) Purchase of auction rate securities (232) (327) Other-net (74) (41) Change in Cash and Cash equivalents (135) $ (617) $ Ending Unrestricted Cash at 6/30/06 980 $ Restricted Cash at 06/30/06 (not included above) 118 $

Exploration & Production Ralph Hill President

2006 Accomplishments 2Q06 production up 20%, 131 MMcfed since 2Q05 6 H&P rigs drilling Additional 12,200 acres Piceance Valley 10-acre spacing approved Piceance Highlands building momentum Big George/Powder River volumes continue impressive growth Barnett Shale position expanding San Juan team awarded Best Management Practices from BLM Exploration & Production Recurring Segment Profit + Depreciation 0 50 100 150 200 250 300 1Q 2Q 3Q 4Q $MM 2005 2006

2006 10-acre Density Applications Approved Exploration & Production 2006 10-Acre Applications Green = Previously Approved - 34,760 Acres Blue = April '06 Approved - 11,200 Acres (approx. 800 additional Bottom Hole Locations) Purple = July '06 Approved - 12,200 Acres (approx. 890 additional Bottom Hole Locations) Williams acreage shown in color Grand Valley Parachute Rulison

Piceance Production Growth Up 104 MMcfed or 34% over a year ago 23 total rigs currently operating in Valley and Highlands compared to 13 a year ago 4 additional H&P FlexRigs to be received in 2006 4 Nabors Super Sundowner rigs to be received in early 2007 Williams will be able to high grade rig fleet Net MMcfe/d Exploration & Production Williams' Total Piceance Production 175 225 275 325 375 425 1Q '05 2Q '05 3Q '05 4Q '05 1Q '06 2Q '06 Highlands Valley

Piceance Highlands - Building Momentum Exploration & Production 44 wells currently producing, up from 8 one year ago 13 MMcfed current net production, up 10 MMcfed year over year 7 rigs currently operating Major road and pipeline infrastructure in progress

Powder River Up 26 MMcfed or 23% over a year ago Big George coals driving basin growth Up 99% year over year June vs. March volumes up 25% Net MMcfe/d Exploration & Production

Douglas Creek Arch Uncompahgre Uplift UTAH ARIZONA COLORADO NEW MEXICO Piceance Basin Uinta Basin Paradox Basin WYOMING Pending Piceance Basin Farm-in Opportunity Drill-to-earn deal pending Targets Williams Fork Formation ~11,000 net acres to Williams 87.5% NRI 600+ potential drill locations Williams to operate Exploration & Production

New Capital Projects Exploration & Production Dollars in millions 5/4/06 Capital Guidance $950 $1,050 $950 $1,050 $1,000 $1,150 New Capital Projects Piceance Additional Drilling 65 50 70 Increased Costs 35 30 30 Gathering & Processing * 40 95 30 Other Rockies & Barnett Shale Opportunities 60 25 20 Subtotal 200 200 150 8/3/06 Capital Guidance $1,150 $1,250 $1,150 $1,250 $1,150 $1,300 Midpoint Changes Segment Profit 25 50 75 DD&A 25 30 25 Segment Profit + DD&A 50 80 100 Production (MMcfed) 20 30 40 * Includes 3rd party contracts 2006 2007 2008

2006-08 Guidance 2006 2007 2008 Segment Profit $550 - 650 $825 - 950 $1,025 - 1,175 525 - 625 775 - 900 950 - 1,100 Annual DD&A 360 - 400 455 - 505 500 - 550 335 - 375 425 - 475 475 - 525 Segment Profit + DD&A $910 - 1,050 $1,280 - 1,455 $1,525 - 1,725 860 - 1,000 1,200 - 1,375 1,425 - 1,625 Capital Spending $1,150 - 1,250 $1,150 - 1,250 $1,150 - 1,300 950 - 1,050 950 - 1,050 1,000 - 1,150 Production (MMcfe/d) 770 - 845 905 - 1,005 990 - 1,140 750 - 825 875 - 975 950 - 1,100 Dollars in millions Exploration & Production Note: 2006-08 hedge information included in Appendix. Note: If guidance has changed, previous guidance from 5/4/06 is shown in italics directly below. Unhedged Price Assumption ($/Mcf) Average San Juan/Rockies Price $6.39 $6.09 $6.10 Average Mid-continent Price $6.55 $6.75 $6.77 NYMEX $7.84 $7.00 $7.00

Key Points - Value Creation Continues An industry leader in production growth, cost efficiencies and reserves replacement Long-term repeatable drilling inventory of significant proved undeveloped, probables, and possibles Strategy remains rapid development of our premier drilling inventory Long history of high drilling success, low finding costs Short time cycle investments, fast cash returns Piceance Highlands significantly contributing Experienced and talented work force Exploration & Production

Midstream Alan Armstrong President

2006 Accomplishments Midstream Recurring Segment Profit + Depreciation Record quarter NGL production rebounding NGL unit margins at record levels Completed dropdown of 25.1% interest in Four Corners Expanding for the future: Opal TXP-IV Opal TXP-V Tahiti lateral Blind Faith Wamsutter gathering 0 20 40 60 80 100 120 140 160 180 200 220 240 260 1Q 2Q 3Q 4Q $ MM 2005 2006

2006-08 Guidance 2006 2007 2008 Segment Profit $550 - 675 $500 - 750 $550 - 800 500 - 600 410 - 530 440 - 580 Annual DD&A 190 - 200 200 - 210 210 - 220 Segment Profit + DD&A $740 - 875 $700 - 960 $760 - 1,020 690 - 800 610 - 740 650 - 800 Capital Spending $280 - 300 $230 - 270 $70 - 90 Dollars in millions Note: If guidance has changed, previous guidance from 05/04/2006 is shown in italics directly below. Midstream Un-Hedged Price Assumptions 2006 2007 2008 1Q-2Q 3Q-4Q NYMEX Natural Gas ($/Mcf) $7.00 $7.84 $7.00 $7.00 NYMEX Oil ($/bbl) $67 $62 - $70 $55 - $69 $55 - $69 Realized Margin (cents/gallon) 26.4

0 100 200 300 400 500 600 700 800 900 1,000 Discretionary Expansion Segment Profit Margin Uplift Base Segment Profit + DDA Discretionary Expansion Historic Expansion Maintenance Well Connects Free Cash Flow - Forecast $'s 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 five year average margin. Capital Seg Profit + DDA Capital Seg Profit + DDA Capital Seg Profit + DDA Capital Seg Profit + DDA Capital Seg Profit + DDA 2004 2005 2006 2007 2008 Capital Spending Recurring Segment Profit & DDA Midstream

Opal Blind Faith Western Deepwater Western Deepwater Overland Pass Significant Progress Made on Growth Projects Western G&P Expansions Deepwater Expansions Overland Pass In Development/Proposal 2006 2007 2008 Spending $500MM-1,500MM 20% 65% Western G&P Expansions ($75MM in guidance) Deepwater Expansions ($30MM in guidance) Under Negotiation 2006 2007 2008 Spending $350MM-550MM 80% 20% Blind Faith Opal TXP-V Opal TXP-IV Tahiti Lateral Contracted/Approved 2006 2007 2008 Spending $280MM 65% 35% In Guidance Not in Guidance 15% Midstream

Key Points Focused on our strategy of reliability Base business continues to generate healthy returns and free cash flows NGL margins exceed historic levels - cushioning enterprise impact of lower gas prices Expect NGL margins to remain above historic levels Progress continues on deepwater expansions Western growth opportunities abound Midstream

2006-08 Consolidated Outlook Don Chappel Chief Financial Officer

2006 Forecast Guidance Consolidated Segment profit before MTM adjustment $1,355 - $1,675 $1,273 - $1,613 Net Interest Expense (670) - (710) (665) - (705) Other (Primarily General Corp. Costs) (105) - (125) (85) - (120) Securities Litigation Settlement & Related Costs (162) - Pretax Income 418 - 678 523 - 788 Provision for Income Tax (185) - (295) (210) - (320) Income from Continuing Ops 233 - 383 313 - 468 Income/(Loss) from Discontinued Ops (5) - 0 (5) - 0 Net Income $228 - 383 $308 - 468 Diluted EPS $0.37 - $0.63 $0.50 - $0.77 Recurring Income from Cont. Ops $414 - $564 $318 - $473 Diluted EPS - Recurring $0.68 - $0.92 $0.52 - $0.78 Diluted EPS - Recurring After MTM Adj. 1 $0.95 - $1.20 $0.78 - $1.03 1 Includes MTM adjustment of $275 million (pretax) in Aug 3 guidance and $255 million (pretax) in May 4 guidance Note: Fully diluted shares of 610 million Dollars in millions, except per-share amounts Aug 3 Guidance May 4 Guidance

Consolidated 2006-08 Segment Profit Dollars in millions Exploration & Production Midstream Gas Pipeline Power Other / Corp. / Rounding Total Reported Before MTM Adj. MTM Adjustment Total Reported After MTM Adj. Nonrecurring Items Total Recurring After MTM Adj. 2006 2007 $550 - 650 550 - 675 1 475 - 520 (200) - (150) (20) $1,355 - 1,675 275 $1,630 - 1,950 60 $1,690 - 2,010 2008 $825 - 950 500 - 750 585 - 655 (175) - (75) 10 - (30) $1,745 - 2,250 225 $1,970 - 2,475 - - $1,970 - 2,475 $1,025 - 1,175 550 - 800 590 - 665 (155) - (5) (15) - 35 $1,995 - 2,670 205 $2,200 - 2,875 - - $2,200 - 2,875 Note: If guidance has changed, previous guidance from 5/4/06 is shown in italics directly below $1,273 - 1,613 500 - 600 255 215 215 $1,528 - 1,868 $1,520 - 1,860 (205) - (105) (165) - (15) (165) - (15) $1,615 - 2,040 $1,800 - 2,365 Power After MTM Adj. $75 - 125 $50 - 150 $50 - 200 $50 - 150 525 - 625 775 - 900 950 - 1,100 $1,830 - 2,255 $1,830 - 2,255 $2,015 - 2,580 $2,015 - 2,580 410 - 530 440 - 580 $50 - 200 (22) - (27) (8) 1 Reflects $68 million of nonrecurring litigation accrual

2006-08 Capital Expenditures Consolidated Exploration & Production Midstream Gas Pipeline Power Other/Corporate Total Dollars in millions Notes: - - Sum of ranges for each business line does not necessarily match total range $1,150 - 1,250 280 - 300 745 - 815 - - 10 - 30 $2,200 - 2,400 $1,150 - 1,250 230 - 270 370 - 470 - - 10 - 30 $1,775 - 1,975 $1,150 - 1,300 70 - 90 340 - 440 - - 10 - 30 $1,575 - 1,825 2006 2008 2007 $950 - 1,050 $950 - 1,050 $1,000 - 1,150 $1,950 - 2,150 $1,600 - 1,800 $1,500 - 1,750 710 - 785 390 - 490 410 - 510

2006-08 Outlook 1 Cash flow from continuing operations. 2 Operating free cash flow is defined as cash flow from continuing operations less capital expenditures, before dividend or principal payments Note: If guidance has changed, previous guidance from 5/4/06 is shown in italics directly below Dollars in millions Segment Profit Reported After MTM Adj. Recurring After MTM Adj. DD&A Cash Flow from Ops.1 Capital Expenditures Operating Free Cash Flow 2 2006 2007 $1,630 - 1,950 1,690 - 2,010 820 - 920 1,500 - 1,800 2,200 - 2,400 (700) - (600) 2008 $ 1,970 - 2,475 1,970 - 2,475 930 - 1,030 2,000 - 2,300 1,775 - 1,975 225 - 325 $2,200 - 2,875 2,200 - 2,875 1,010 - 1,110 2,425 - 2,825 1,575 - 1,825 850 - 1,000 $1,528 - 1,868 Consolidated (450) - (350) $1,520 - 1,860 790 - 890 900 - 1,000 1,950 - 2,150 1,600 - 1,800 1,500 - 1,750 250 - 350 700 - 850 1,000 - 1,100 $1,830 - 2,255 $1,830 - 2,255 $2,015 - 2,580 $2,015 - 2,580 1,850 - 2,150 2,200 - 2,600

Strong Operating Cash Flow Growth & Increasing Investment Opportunities Consolidated 2003 2004 2005 2006 2007 2008 Cap Ex-Low 790 1415 2200 1775 1575 Cap Ex-High 790 1415 2400 1975 1825 CFFO-Low 588 1472 1450 1500 2000 2425 CFFO-High 588 1472 1450 1800 2300 2825 Debt to Cap 0.75 0.623 0.586 0.56 0.54 0.51 0.75 0.623 0.586 0.58 0.56 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% 56% to 58% 54% to 56% $790 Opportunity Rich Declining Debt / Cap % $2,425 to $2,825 59% 51% to 53% $1,415 3 $1,450 $1,575 to $1,825 $1,775 to $1,975 Cap Ex Increasing Cash Flow $1,500 to $1,800 $2,200 to $2,400 $2,000 to $2,300

Financial Strategy/Key Points Drive/enable sustainable growth in EVA(r) / shareholder value Strategy to accelerate delivery of MLP benfits to WMB Continue to maintain and/or improve credit ratios/ratings Reduce risk in Power segment Opportunity rich Increasing focus and disciplined EVA(r)-based investments in natural gas businesses Attractive EVA(r) -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(r) drives value creation Consolidated

Summary Steve Malcolm Chairman, President & CEO

Summary Execution of strategy delivers very strong 2Q Nearly DOUBLED recurring income after removing mark-to-market effect Raising profit guidance for '06, '07 and '08 19% jump up in guidance for '06 key earnings measure* Boosting planned capital expenditures to develop reserves MLP strategy to accelerate delivery of benefits to Williams *Recurring income from continuing operations after mark-to-market adjustment

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 Reconciliation of Income (Loss) from Continuing Operations to Recurring Earnings (Loss) (UNAUDITED) (Dollars in millions, except per-share amounts) 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr Year Income from continuing operations available to common stockholders $202.2 $40.7 $5.7 $68.8 $317.4 $131.1 ($63.9) $67.2 Income (loss) from continuing operations - diluted earnings (loss) per common share $0.34 $0.07 $0.01 $0.11 $0.53 $0.22 ($0.11) $0.11 Nonrecurring items: Exploration & Production Gain on sale of E&P properties (7.9) - - (21.7) - - (29.6) - - - - - - Loss provision related to an ownership dispute 0.3 - - - - - - 0.3 - - - - - - Total Exploration & Production nonrecurring items (7.6) - - (21.7) - - (29.3) - - - - - - Gas Pipeline Prior period liability corrections - TGPL (13.1) (4.6) - - - - (17.7) - - - - - - Prior period pension adjustment - TGPL - - (17.1) - - - - (17.1) - - - - - - 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 - - - - - - Reversal of litigation contigency due to favorable ruling - TGPL - - - - - - - - - - (2.0) - - (2.0) Total Gas Pipeline nonrecurring items (13.1) (21.7) (14.2) 37.3 (11.7) (2.0) - - (2.0) Midstream Gas & Liquids Accrual for Gulf Liquids litigation contingency - - - - - - - - - - - - 68.0 68.0 Settlement of an international contract dispute - - - - - - - - - - (6.3) - - (6.3) Total Midstream Gas & Liquids nonrecurring items - - - - - - - - - - (6.3) 68.0 61.7 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 - - - - - - Other Impairment of Longhorn - - 49.1 - - 38.1 87.2 - - - - - - Write-off of capitalized project development costs - - 4.0 - - - - 4.0 - - - - - - Gain on sale of real property - - - - - - (9.0) (9.0) - - - - - - Total Other nonrecurring items - - 53.1 - - 29.1 82.2 - - - - - - Nonrecurring items included in segment profit (loss) (9.3) 44.5 (35.5) 158.1 157.8 (8.3) 68.0 59.7 Nonrecurring items below segment profit (loss) 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) 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 - - - - - - Securities litigation settlement and related costs (1) - - - - - - 9.4 9.4 1.2 160.7 161.9 Reversal of interest accrual related to reversal of litigation contingency noted above (Interest accrued - Gas Pipeline - TGPL) - - - - - - - - - - (5.0) - - (5.0) Early debt retirement costs (Corporate and Exploration & Production) - - - - - - - - - - 27.0 (1) 4.4 31.4 Gain on sale of Algar/Triangulo shares (Investing income / loss - Other) - - - - - - - - - - (6.7) - - (6.7) Interest related to Gulf Liquids litigation contingency ( Interest accrued - Midstream) - - - - - - - - - - - - 20.0 20.0 2.7 (8.6) 18.8 9.4 22.3 16.5 185.1 201.6 Total nonrecurring items (6.6) 35.9 (16.7) 167.5 180.1 8.2 253.1 261.3 Tax effect for above items (1) (2.8) 10.7 (6.4) 48.0 49.5 3.4 76.6 80.0 Adjustment for nonrecurring excess deferred tax benefit - - - - - - (20.2) (20.2) - - - - - - Recurring income (loss) from continuing operations available to common stockholders $198.4 $65.9 ($4.6) $168.1 $427.8 $135.9 $112.6 $248.5 Recurring diluted earnings (loss) per common share $0.33 $0.11 ($0.01) $0.28 $0.72 $0.23 $0.19 $0.42 Weighted-average shares - diluted (thousands) 599,422 578,902 580,735 609,106 605,847 607,073 595,561 598,634 2005 2006 (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. The tax rate applied to Midstream's international contract dispute settlement in 1st quarter 2006 is 34%. The tax rate applied to nonrecurring items for 2nd quarter 2006 has been adjusted for the effect of nondeductible expenses associated with securities litigation settlement and related costs and early debt retirement costs related to our convertible debt. 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 Reconciliation Schedule Non-GAAP Reconciliation Reconciliation of Segment Profit to Recurring Segment Profit (UNAUDITED) (Dollars in millions) 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr Year Segment profit (loss): Exploration & Production 103.7 $ 118.3 $ 158.8 $ 206.4 $ 587.2 $ 147.6 $ 119.8 $ 267.4 $ Gas Pipeline 167.4 164.5 161.1 92.8 585.8 134.7 122.7 257.4 Midstream Gas & Liquids 128.6 109.1 121.1 112.4 471.2 151.5 130.7 282.2 Power 114.1 (75.0) (226.4) (69.4) (256.7) (22.5) (79.6) (102.1) Other (4.1) (60.5) (10.1) (30.3) (105.0) 1.0 (0.7) 0.3 Total segment profit 509.7 $ 256.4 $ 204.5 $ 311.9 $ 1,282.5 $ 412.3 $ 292.9 $ 705.2 $ Nonrecurring adjustments: Exploration & Production (7.6) $ - - $ (21.7) $ - - $ (29.3) $ - - $ - - $ - - $ Gas Pipeline (13.1) (21.7) (14.2) 37.3 (11.7) (2.0) - - (2.0) Midstream Gas & Liquids - - - - - - - - - - (6.3) 68.0 61.7 Power 11.4 13.1 0.4 91.7 116.6 - - - - - - Other - - 53.1 - - 29.1 82.2 - - - - - - Total segment nonrecurring adjustments (9.3) $ 44.5 $ (35.5) $ 158.1 $ 157.8 $ (8.3) $ 68.0 $ 59.7 $ Recurring segment profit (loss): Exploration & Production 96.1 118.3 137.1 206.4 557.9 147.6 119.8 267.4 Gas Pipeline 154.3 142.8 146.9 130.1 574.1 132.7 122.7 255.4 Midstream Gas & Liquids 128.6 109.1 121.1 112.4 471.2 145.2 198.7 343.9 Power 125.5 (61.9) (226.0) 22.3 (140.1) (22.5) (79.6) (102.1) Other (4.1) (7.4) (10.1) (1.2) (22.8) 1.0 (0.7) 0.3 Total recurring segment profit 500.4 $ 300.9 $ 169.0 $ 470.0 $ 1,440.3 $ 404.0 $ 360.9 $ 764.9 $ Note: Segment profit (loss) includes equity earnings (loss) and certain income (loss) from investments reported in Investing income (loss) in the Consolidated Statement of Operations. Equity earnings (loss) results from investments accounted for under the equity method. Income (loss) from investments results from the management of certain equity investments. 2005 2006

Non-GAAP Reconciliation Schedule - EPS after MTM adjustment Non-GAAP Reconciliation Dollars in millions except per share amounts 1Q 2Q 3Q 4Q Year Recurring income from cont. ops available to common shareholders 136 $ 113 $ 249 $ Recurring diluted earnings per common share 0.23 $ 0.19 $ 0.42 $ Mark-to-Market (MTM) adjustments: Reverse forward unrealized MTM gains/losses (43) 38 (5) Add realized gains/losses from MTM previously recognized 77 100 177 Total MTM adjustments 34 138 172 Tax effect of total MTM adjustments 13 53 66 After tax MTM adjustments 21 85 106 Recurring income from cont. ops available to common shareholders after MTM adjust. 157 $ 198 $ 355 $ Recurring diluted earnings per share after MTM adj. 0.26 $ 0.33 $ 0.59 $ weighted average shares - diluted (thousands) 607,073 595,561 598,634 1Q 2Q 3Q 4Q Year Recurring income from cont. ops available to common shareholders 198 $ 66 $ (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 $ 100 $ 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 2005 2006

EBITDA Reconciliation Non-GAAP Reconciliation Dollars in millions 2Q06 YTD Net Income (Loss) (76) $ 56 $ Loss from Discontinued Operations 12 11 Net Interest Expense 178 337 DD&A 210 408 Provision for Income Taxes 1 89 EBITDA 325 $ 901 $

2Q 2006 Segment Contribution Non-GAAP Reconciliation Dollars in Millions Corp/ E&P Midstream Gas Pipeline Power Other Total Segment Profit (Loss) 120 $ 131 $ 123 $ (80) $ (1) $ 293 $ DD&A 84 50 71 3 2 210 Segment Profit before DDA 204 $ 181 $ 194 $ (77) $ 1 $ 503 $ General corporate expenses (34) Securities litigation settlement and related costs (161) Investing income* 21 Other income (4) TOTAL 325 $ * Excluding equity earnings and income (loss) from investments contained in segment profit

2006 Forecast EBITDA Reconciliation Non-GAAP Reconciliation Net Income $228 - 383 $308 - 468 Loss from Disc. Ops. 5 - 0 5 - 0 Net Interest 670 - 710 665 - 705 DD&A 820 - 920 790 - 890 Provision for Income Taxes 185 - 295 210 - 320 Other/Rounding (8) (3) - (8) EBITDA $1,900 - 2,300 $1,975 - 2,375 MTM Adjustments 275 255 EBITDA - After MTM Adj. $2,175 - 2,575 $2,230 - 2,630 Dollars in millions Aug 3 Guidance May 4 Guidance

2006 Forecast Segment Contribution Non-GAAP Reconciliation Power 1 $(200) - (150) 10 - 20 $(190) - (130) Gas Pipeline $475 - 520 280 - 300 $755 - 820 Segment Profit (Loss) DD&A Segment Profit Before DDA Other (Primarily General Corporate Expense & Investing Income) Securities Litigation Settlement and Related Costs Rounding TOTAL E&P $550 - 650 360 - 400 $910 - 1,050 Midstream $550 - 675 190 - 200 $740 - 875 Total $1,355 - 1,675 820 - 920 $2,175 - 2,595 (105) - (125) (162) (8) $1,900 - 2,300 Corp/ Other $(20) (20) - 0 $(40) - (20) Dollars in millions 1 Segment Profit is prior to MTM adjustments

2006 Forecast Guidance Contribution Non-GAAP Reconciliation Net Income $228 - 383 $308 - 468 Less: Discontinued Operations (Loss) (5) - 0 (5) - 0 Income from Continuing Ops $233 - 383 $313 - 468 Non-Recurring Items (Pretax) 261 8 Less Taxes 80 3 Non-Recurring After Tax 181 5 Recurring Income from Cont. Ops $414 - 564 $318 - 473 Recurring EPS $0.68 - $0.92 $0.52 - $0.78 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 275 107 168 $582 - 732 $0.95 - $1.20 255 99 156 $474 - 629 $0.78 - $1.03 Dollars in millions, except per-share amounts May 4 Guidance Aug 3 Guidance

Appendix

Rockies Producer Not Rockies Price Taker Exploration & Production Powder River Piceance San Juan Glenrock Opal Wamsutter Cheyenne Greasewood Blanco Meeker CIG NWPL Questar Rockies Express TransColorado WIC Pipes Used to Move Williams ' Gas Trailblazer Firm Access Under Contract North to Wamsutter 200 East to Mid - -continent 209 South to San Juan 285 East to Appalachia (REX) 200 West to Opal 150 2008 - - 2009 adds

Cash Margin Analysis Exploration & Production 3-Year Average (2006-08) Reflective of core basins $5.65 is after hedging and includes average basin market price of $6.41 before hedging Cash costs include LOE, G&A, taxes and gathering F&D costs include acquisition and development expenditures/proved reserves ('03-'05 average) $5.55 Previous Previous $3.82 $1.73 Cash Margin Cash Costs $5.65 $1.75 $0.92 $3.90 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 Realized Gas Price Assumption Margin/Cost Assumption F&D Costs

2Q Net Realized Price Summary Exploration & Production Unhedged Hedge Market Price: NYMEX including collars $6.90 - $7.20 4.53 Basis Differential (1.40 - 1.60) (0.57) Net basin market price $5.30 - $5.80 $3.96 Net basin market price $5.30 - $5.80 $3.96 Fuel & Shrinkage/Gathering/ (0.60 - 0.80) (0.50 - 0.60) Transportation Net Price $4.50 - $5.20 $3.36 - $3.46 Quarter Volume Totals (qtr daily volumes (qtr daily - - qtr daily volumes) hedge volumes) x (91/1000) x (91/1000) Net Gas Revenue =(unhedged =(hedged volumes x net volumes x net price) hedge price) 2Q '06

2006 2007 2008 Fixed Price at the basin: Volume (MMcf/d) 297 172 73 Average Price ($/Mcf) $3.84 $3.90 $3.96 NYMEX Collars: Volume (MMcf/d) 64 15 - Average Price ($/Mcf) $6.62 - $8.42 $6.50 - $8.25 At the Basin Collars:1 NWPL Rockies Volume (MMcf/d) 50 50 75 Price ($/Mcf) $6.05 - $7.90 $5.65 - $7.45 $6.02 - $9.52 EPNG San Juan Volume (MMcf/d) - 130 25 Average Price ($/Mcf) $5.98 - $9.63 $6.20 - 9.57 Mid-Continent Volume (MMcf/d) - 70 - Price ($/Mcf) $6.78 - $10.89 2006-08 Hedge Update Exploration & Production Dollars in millions 1 Please note basin locations are not NYMEX 3Q-4Q

Douglas Creek Arch Uncompahgre Uplift UTAH ARIZONA COLORADO NEW MEXICO Piceance Basin Uinta Basin Paradox Basin WYOMING E&P Opportunities - Previously Announced Piceance Basin: Shale Ridge Prospect (Dakota Sandstone play) Leased 13,904 gross/net acres 100% WI; 87.5% NRI 10-year lease term 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 Exploration & Production

Exploration & Production Piceance Highlands - Results to Date Project Area Wells Drilled and Completed Average 30 Day Rate/Completed Well (MMcfed) Expected EUR* Range (Bcfe/well) Trail Ridge 18 1.2 1.2 - 1.8 West Grand Valley 2 1.3 1.2 - 1.8 Ryan Gulch 14 1.2 1.2 - 2.0 Allen Point 6 1.2 1.2 - 1.6 * Estimated Ultimate Recovery

Exploration & Production Piceance Highlands Project Summary 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) 21,512 1,500 1,500-2,000 3 12 20 West Grand Valley (10-acre density) 1,080 90 80 1 1 0 Ryan Gulch (40-acre density) 16,078 800 700 3 5 22* Allen Point (40-acre density) 6,240 200 140 0 6 9 Total 44,910 2,590 2,420-2,920 7 24 51 * 3 wells non-operated

Pricing Assumptions Included in Guidance Midstream Historic Prices Guidance Pricing Assumptions 0 10 20 30 40 50 60 70 80 90 '00 '01 '02 '03 '04 '05 1Q06 2Q06 $/bbl 0 2 4 6 8 10 12 14 $/MMBtu Oil WTI ($/bbl) Nat Gas Henry Hub ($/MMBtu) 0 10 20 30 40 50 60 70 80 90 3Q-4Q06 2007 2008 $/bbl 0 2 4 6 8 10 12 14 $/MMBtu High Oil Low Oil Nat Gas Henry Hub ($/MMBtu)

Margins Above Average Midstream Note: Actual realized margins, does not include Discovery volumes. Five year average of 13.2 cpg is calculated for the period 3Q01-2Q06. Domestic NGL Average Realized Net Margin and Volumes by Quarter Realized Margin Total NGL Prod (MM Gals) Equity NGL Sales (MM Gals) Avg. Realized Margin 0 5 10 15 20 25 30 35 Q1'02 Q2'02 Q3'02 Q4'02 Q1'03 Q2'03 Q3'03 Q4'03 Q1'04 Q2'04 Q3'04 Q4'04 Q1'05 Q2'05 Q3'05 Q4'05 Q1'06 Q2'06 0 100 200 300 400 500 600 700 800 Realized Margin (Cents / Gallon) Total Production & Equity Volumes by Quarter (MM Gallons)

2006 Accomplishments Northwest: Filed rate case on June 30, 2006. The anticipated effective date is January 1, 2007 Open season begins for long-term firm transportation service for Greasewood Lateral expansion FERC certificate application filed for Jackson Prairie Expansion Completed $175 million offering of senior unsecured notes due 2016 Transco: Leidy to Long Island Expansion project receives FERC approval FERC certificate application filed for Potomac Expansion Completed $200 million offering of senior unsecured notes due 2016 Gulfstream: Executed agreement with Progress Energy to provide 155 MDth/d to its Bartow Power Plant with the Gulfstream Phase IV expansion project Gas Pipeline Recurring Segment Profit + Depreciation 0 50 100 150 200 250 1Q 2Q 3Q 4Q 2005 2006

2006-08 Guidance 2006 2007 2008 Segment Profit $475 - 520 $585 - 655 $590 - 665 Annual DD&A 280 - 300 290 - 310 295 - 315 Segment Profit + DD&A $755 - 820 $875 - 965 $885 - 980 Capital Spending $745 - 815 $370 - 470 $340 - 440 Dollars in millions Note: If guidance has changed, previous guidance from 05/04/06 is shown in italics directly below. Gas Pipeline 390 - 490 410 - 510 710 - 785

2006-08 Capital Spending Detail 2006 2007 2008 Normal Maintenance/Compliance $375 - 435 $210 - 265 $180 - 260 Northwest 26-inch Replacement 276 2 - Expansion1 95 - 105 160 - 200 160 - 180 Total $745 - 815 $370 - 470 $340 - 440 Dollars in millions Note: If guidance has changed, previous guidance from 05/04/06 is shown in italics directly below. Gas Pipeline Note: - Sum of ranges may not necessarily match total range 1Major Growth Projects (in guidance): 2006 2007 2008 1st full yr Seg. Profit Parachute (In Service 1/07) $55 - 65 $9 Leidy to Long Island (In Service11/07) 10 - 15 $85 - 100 $1 - 5 20 Potomac (In Service 11/07) 5 - 10 55 - 65 1 - 5 11 Sentinel (In Service 11/08) 1 - 5 5 - 15 110 - 130 22 Greasewood (In Service 11/08) 25 - 30 5 180 - 220 230 - 250 390 - 490 410 - 510 340 - 405 710 - 785

Sentinel Nov 2008 Growth Projects and Opportunities Update Gulfstream Phase IV Jan 2009 Leidy to Long Island Nov 2007 Potomac Nov 2007 Parachute Jan 2007 Pacific Connector Pipeline Late 2010 Greasewood Nov 2008 Jackson Prairie Nov 2008 Gas Pipeline Gulfstream Phase III Summer 2008 Equity Investments

Design - 360 MMcfd Scope of Work Approx. 80 miles of 36" pipeline 10,760 net horsepower added Station Modifications 268 miles of 26" pipeline retired Capital Costs on target - $333 MM Schedule FERC Certificate - 9/2005 Start HDD - 10/2005 Sta. & P/L Mobilized - 5/2006 Construction - Summer 2006 In-service - 11/ 2006 (In rates - 1/2007) Capacity Replacement Project on Track Gas Pipeline

Key Points 26-inch Replacement on target to be in-service November 1st Growth projects progressing Rate Case filings continue on target Northwest filed Jun 30th, effective Jan 1st Transco to file Aug 31st, effective Mar 1st Gas Pipeline

Long-term Free Cash Flow Gas Pipeline Note: - - Segment Profit is stated on a recurring basis. - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges for 2006 - 2008. 2005 2006 2007 2008 Seg Profit + DDA Seg Profit + DDA Capital Spending Expansion 26-inch Replacement Maint/Compliance 0 100 200 300 400 500 600 700 800 900 1000

Dollars in millions 2006 2007 2008 Prior Guidance - Segment Loss before MTM Adj ($205) - (105) ($165) - (15) ($165) - (15) Est. Fwd Impact of 2Q06 MTM Earnings and other portolio adjustments New Guidance - Segment Loss before MTM Adj ($200) - (150) ($175) - (75) ($155) - (5) ($205) - (105) ($165) - (15) ($165) - (15) Estimated MTM Adjustments 275 225 205 255 215 215 Segment Profit after MTM Adj 75 - 125 50 - 150 50 - 200 Recurring Segment Profit after MTM Adj $75 - 125 $50 - 150 $50 - 200 $50 - 150 $50 - 200 Capital Expenditures - - - - - - $5 - (45) ($10) - (60) $10 - 10 2006-08 Guidance Note: If guidance has changed, previous guidance from 5/04/06 is shown in italics directly below. Power

YTD 2006 - Segment Profit/(Loss) to Cash Flow from Ops Power 1Significant amount of Working Capital used was returned to two counterparties due to commodity settlements and commodity price changes. 2Collateral returned does not impact total WMB liquidity because collateral received is excluded from calculation of available WMB liquidity. 3CFFO includes cash margin dollars sent out on behalf of other business units. Dollars in Millions Commodity Working Power Capital/ & NG Other Total Segment Loss ($88) ($14) ($102) MTM Adjustments: Reverse Forward Unrealized MTM (Gains) (4) (4) Add Realized Gains from MTM Previously Recognized 177 177 Segment Profit/(Loss) After MTM Adjustments 85 (14) 71 Total Working Capital Change 1,2&3 (324) (324) Power Segment CFFO $85 ($338) ($253)

Power Portfolio Cash Flow Analysis Estimated undiscounted dollars in millions 1 Q206 Actual cash flows are realized from a combination of Hedged Cash Flows and Merchant Cash Flows and other risk management and trading activities. Q206 forecast combines Hedged Cash Flow and Merchant Cash Flow estimates to present comparable to actual. 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 YTD SG&A includes $24 million gain related to sale of certain Enron receivables 5 Working Capital & Other changes are zero in future periods, as they are not reasonable estimable. Note: Q206 Forecast estimated as of 12/31/05. 2007 forward forecast estimated as of 6/30/06. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding. Power Power Portfolio Actual vs. Forecast 2006 2Q06A 2Q06F YTD06A YTD06F 2006A+F 2007F 2008F Tolling Demand Payment Obligations ($96) ($99) $3 ($182) ($185) $3 ($397) ($406) ($412) Hedged Cash Flows 2 576 476 496 Merchant Cash Flows 3 31 89 78 SG&A and Other 4 (20) (21) 1 (19) (42) 23 (64) (85) (80) Total Power Portfolio Cash Flows $35 $40 ($5) $81 $69 $12 $146 $74 $82 Working Capital & Other 5 (288) n/a (334) n/a n/a n/a n/a Estimated Power Segment Cash Flows ($253) ($253) YTD Variance 282 1 (14) 296 QTD Variance 151 1 160 (9)

2Q06 Financial Statement Changes for Derivatives Power During 2Q06, 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 2Q06 decrease in gas prices against a short derivative position The net change in Derivative Assets and Liabilities for Midstream was negative reflecting the 2Q06 price increase on crude and NGL's against a short derivative position The net change in Derivative Assets and Liabilities for Power was negative, reflecting the 2Q06 decrease in gas prices against a long derivative position 1 Change in OCI shown is before taxes. Therefore, change shown does not tie to balance sheet change which is net of taxes. Dollars in millions Der A/L OCI MTM Gain/(Loss) Realized (Gain)/Loss Total Change in Consolidated Derivative Values 1 ($60) $45 ($33) ($72) Less change in Option Premiums/Prudency/Other (1) (1) Remaining Change in Consolidated Derivative Values ($59) $45 ($33) ($71) Change in E&P Hedge Values 135 86 6 - Prior MTM Realized (Ineffectiveness) (7) - OCI Realized 50 Change in Midstream Hedge Values (21) (21) - Prior MTM Realized (0) - OCI Realized (0) Change in Power Hedge Values (173) (20) (39) - Prior MTM Realized (100) - OCI Realized (14) Balance Sheet Income Statement

West Undiscounted Cash Flows Power Dollars in millions 1 Q206 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: Q206 Forecast estimated as of 12/31/05. 2007 forward forecast estimated as of 6/30/06. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding. West Power Portfolio Estimated as of 6/30/06 Q206A Q206F QTD Variance 2006F+A 2007F 2008F Tolling Demand Payment Obligations ($38) ($38) $0 ($154) ($157) ($159) Hedged Cash Flows 2 439 376 355 Merchant Cash Flows 3 (3) 9 9 Total Cash Flows $79 $68 $11 $282 $228 $205 Capacity Available (in MW) 3,805 3,805 3,805 Total Capacity Sold 2,772 3,329 3,452 Remaining Available (in MW) after all hedges 1,033 476 353 117 1 106 11

Mid-Con Undiscounted Cash Flows Power 1 Q206 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: Q206 Forecast estimated as of 12/31/05. 2007 forward forecast estimated as of 6/30/06. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding. Dollars in millions Mid-Continent Power Portfolio Estimated as of 6/30/06 Q206A Q206F QTD Variance 2006F+A 2007F 2008F Tolling Demand Payment Obligations ($21) ($22) $1 ($88) ($89) ($90) Hedged Cash Flows 2 37 49 Merchant Cash Flows 3 22 9 Total Cash Flows ($12) ($11) ($1) ($39) ($30) ($32) Capacity Available (in MW) 1,303 1,303 1,303 Total Capacity Sold 401 346 365 Remaining Available (in MW) after all hedges 902 957 938 (2) 49 1 9 1 11

East Undiscounted Cash Flows Power 1 Q206 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: Q206 Forecast estimated as of 12/31/05. 2007 forward forecast estimated as of 6/30/06. Variances between regional Cash Flow slides and total Cash Flow Analysis slide may be due to rounding. Dollars in millions East Power Portfolio Estimated as of 6/30/06 Q206A Q206F QTD Variance 2006F+A 2007F 2008F Tolling Demand Payment Obligations ($36) ($39) $3 ($155) ($160) ($162) Hedged Cash Flows 2 63 90 Merchant Cash Flows 3 59 60 Total Cash Flows ($12) $2 ($14) ($32) ($38) ($12) Capacity Available (in MW) 2,280 2,280 2,280 Total Capacity Sold 1,561 631 583 Remaining Available (in MW) after all hedges 719 1,649 1,697 (17) 123 1 25 1 42

WMB Collateral Outstanding Enterprise Risk Management $ $ $ $ $ As of 6/30/06 Corp./ Dollars in millions E&P Midstream Power Other Total Margins & Ad. Assur. $224 $0 $18 $0 $242 Prepayments 0 0 11 0 11 Subtotal 224 0 29 0 253 Letters of Credit 387 109 397 65 958 Total as of 6/30/06 611 109 426 65 1211 Total as of 12/31/05 746 243 343 91 1423 Change ($135) ($134) $83 ($26) ($212)

WMB Collateral Sensitivity Enterprise Risk Management Dollars in millions Margin Volatility (1% chance of exceeding) -Potential incremental collateral requirement Days 6/30/2006 3/31/2006 12/30/2005 9/30/2005 30 ($246) ($223) ($325) ($469) 180 ($580) ($769) ($559) ($868) 360 ($489) ($626) ($567) ($926) Assumption: The Margin numbers above consist of only forward marginable positions.

Sensitivity Analysis Dollars in millions, except per unit increases Enterprise Risk Management Enterprise 1 Power Co. 2 Midstream 3 Natural Gas Power Processing Margin Per MMBtu Per MWh Per Gallon of NGL's Increase $0.10 $1 $0.01 2006 $0-$2 MM $0-$2 MM $3-$8 MM 2007 $6-$9 MM $3.5-$5.5 MM $11-$16 MM 2008 $25-$28 MM $6-$8 MM $10-$15 MM

Natural Gas Outright Position Enterprise Risk Management - -500,000 - -400,000 - -300,000 - -200,000 - -100,000 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 2006 2007 2008 E&P Gross Position E&P Net Position Midstream Fuel & Shrink Enterprise Net Position MMBtu/Day

Debt Balance1 Avg. Cost 1 Debt is long-term debt due within 1 year plus long-term debt. Dollars in millions Debt Balance @ 12/31/05 $7,713 7.6% Early Conversions (220) Scheduled Debt Retirements & Amortization (64) Debt Balance @ 3/31/06 $7,429 7.7% Fixed Rate Debt @ 06/30/06 $7,309 7.7% Variable Rate Debt @ 06/30/06 $154 6.1% Consolidated Additions 699 Early Retirements (485) Scheduled Debt Retirements & Amortization (180) Debt Balance @ 6/30/06 $7,463 7.7%

Dollars in millions Debt Amortization - As of 6/30/2006 Consolidated 49 392 239 54 217 1168 80 22 1,850 2,020 998 385 8 10 $0 $250 $500 $750 $1,000 $1,250 $1,500 $1,750 $2,000 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019-2027 2028-2032 2033

Diluted EPS from Cont. Ops. $0.22 ($.11) - - $0.11 Recurring EPS 0.23 0.19 - - 0.42 Recurring EPS after MTM Adj. 0.26 0.33 - - 0.59 Average Shares (MM) 607 596 - - 599 2006 1Q 2Q 3Q 4Q Total 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 EPS Metrics Consolidated

2006 Interest Expense Forecast Guidance Consolidated Interest on Long-Term Debt $570 - $590 Amortization Discount/Premium and other Debt Expense 25 - 30 Credit Facilities: (incl. Commitment Fees plus LC Usage) 40 - 50 Interest on other Liabilities 43 - 53 Interest Expense $678 - $723 Less: Capitalized Interest (8) - (13) Net Interest Expense Guidance $670 - $710 Dollars in millions 2006

2006 Effective Tax Rates Consolidated Statutory Rate 77 35% (22) 35% 55 35% State 10 5% (1) 1% 9 6% Foreign 0 0% 7 - -10% 7 4% Nondeductible Expenses (Shareholder Litigation/Convertible Debentures) 0 0% 18 - -28% 18 12% Other 1 0% (1) 1% 0 0% Tax Provision/(Benefit) 88 40% 1 - -1% 89 57% Effective Tax Rate Guidance 1 Cash Tax Rate Guidance 2 Note 1: Additional income tax expense of $25-35 million in 2006, $10-15 in 2007 and $5-10 million in 2008 is also forecast. Note 2: Discontinued operations in 2006 have an immaterial impact. 2006 First Quarter Second Quarter Year-to-Date 2006 2007 2008 39% 39% 39% 10-15% 5-10% 9-14%

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