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): November 1, 2007

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 November 1, 2007, The Williams Companies, Inc. (“Williams” or the “Company”) issued a press release announcing its financial results for the quarter ended September 30, 2007. 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 9.01. Financial Statements and Exhibits.

(a) None

(b) None

(d) Exhibits


Exhibit 99.1		Copy of Williams’ press release dated November 1, 2007, and its accompanying highlights and reconciliation schedules, publicly announcing its third quarter 2007 financial results.

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: November 1, 2007	/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 November 1, 2007, and its accompanying highlights and reconciliation schedules, publicly announcing its third quarter 2007 financial results.

exv99w1

Exhibit 99.1



News Release

NYSE: WMB

Date: Nov. 1, 2007

Williams Reports Third-Quarter 2007 Financial Results

•

Natural Gas Businesses Continue Strong 2007 Performance — $228 Million Income from Continuing Operations During 3Q

•

Key Measure – 3Q Recurring Adjusted EPS – Is Up 44% Over 2006

•

Earnings Guidance Increased for 2007, Updated for 2008

•

Strong NGL Margins, Production Increases, New Pipeline Rates Drive Performance

Quarterly Summary Financial Information
Per share amounts are reported on a fully diluted basis


	3Q 2007						3Q 2006
	millions			per share			millions			per share
Income from continuing operations	$	227.9		$	0.38		$	112.9		$	0.19
Loss from discontinued operations	$	(29.9	)	$	(0.05	)	$	(6.7	)	$	(0.01	)

Net income	$	198.0		$	0.33		$	106.2		$	0.18


Recurring income from continuing operations*	$	219.3		$	0.36		$	121.9		$	0.20
After-tax mark-to-market adjustments	$	19.8		$	0.03		$	42.3		$	0.07

Recurring income from continuing operations — after mark-to-market adjustment*	$	239.1		$	0.39		$	164.2		$	0.27

Year-to-Date Summary Financial Information
Per share amounts are reported on a fully diluted basis


	YTD 2007				YTD 2006
	millions		per share		millions			per share
Income from continuing operations	$	641.5	$	1.05	$	185.9		$	0.31
Income (loss) from discontinued operations	$	123.6	$	0.20	$	(23.8	)	$	(0.04	)

Net income	$	765.1	$	1.25	$	162.1		$	0.27


Recurring income from continuing operations*	$	606.5	$	0.99	$	376.2		$	0.62
After-tax mark-to-market adjustments	$	86.1	$	0.15	$	99.1		$	0.17

Recurring income from continuing operations — after mark-to-market adjustment*	$	692.6	$	1.14	$	475.3		$	0.79


*		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 (NYSE: WMB) 3Q 2007 Financial Results — Nov. 1, 2007		Page 1 of 11

TULSA, Okla. – Williams (NYSE:WMB) announced unaudited third-quarter 2007 net income of $198 million, or 33 cents per share on a diluted basis, compared with a net income of $106.2 million, or 18 cents per share on a diluted basis for third-quarter 2006.

Year-to-date through Sept. 30, Williams reported net income of $765.1 million, or $1.25 per share on a diluted basis, compared with net income of $162.1 million, or 27 cents per share, for the first nine months of 2006.

Significant increases in income from continuing operations contributed to the net income growth in the third quarter and year-to-date periods. The year-to-date period also benefited from the absence of $248.7 million of litigation related pre-tax charges recorded in second-quarter 2006.

Continued strong performance in all of the company’s core natural gas businesses contributed to the increase in income from continuing operations in both periods. Key factors were continued strong natural gas production growth, natural gas liquid (NGL) margins remaining at historically high levels and the positive effect of new rates on two pipeline systems.

All prior-period amounts presented throughout this report have been recast to reflect certain components of the former Power segment as discontinued operations.

Income or loss from discontinued operations includes the results of the company’s portfolio of power-related contracts, including its portfolio of tolling, full-requirements and tolling-resale contracts, as well as related hedges, and the Hazleton power generation plant.

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

Williams is continuing its practice of providing an analysis of recurring earnings adjusted to remove the effect on its results of mark-to-market accounting for certain hedges and other derivatives.

For a period of time, the company expects to have mark-to-market volatility in Gas Marketing, as that segment has retained certain natural gas legacy contracts and positions from the former Power segment.

For third-quarter 2007, recurring income from continuing operations after mark-to-market adjustments was $239.1 million, or 39 cents per share, compared with $164.2 million, or 27 cents per share for the same period in 2006.

For the first nine months of 2007, recurring income from continuing operations after mark-to-market adjustments was $692.6 million, or $1.14 per share, compared to $475.3 million or 79 cents per share for the first three quarters of 2006.

Strong performance in all of the company’s core natural gas businesses contributed to the higher results on an adjusted basis for both the third quarter and year-to-date periods. Key factors were continued strong natural gas production growth, high NGL margins, the positive effect of new rates on two pipeline systems and a reduction in effective tax rate.



Williams (NYSE: WMB) 3Q 2007 Financial Results — Nov. 1, 2007		Page 2 of 11

Recurring earnings exclude items of income or loss that the company characterizes as unrepresentative of its ongoing operations. A reconciliation of the company’s income from continuing operations to recurring adjusted earnings measures accompanies this news release.

CEO Perspective

“Williams’ natural gas businesses continue to perform at exceptional levels, highlighted by strong growth in earnings – both in the third quarter and year-to-date,” said Steve Malcolm, chairman, president and chief executive officer. “Increasing our earnings guidance for 2007 underscores this high level of performance.

“We continue to demonstrate the value of our businesses. High NGL prices, along with low gas prices in the Rockies, continued to drive record-level NGL margins for our Midstream business; and despite the low basin gas prices, our E&P business continues to perform well. As a result of our transportation agreements and hedges, 93 percent of our domestic production during the quarter was not exposed to the low Rockies pricing,” Malcolm said.

“We also continue to deliver on our strategy to enhance shareholder value. We’re executing on our MLP strategy – with both Williams Partners and the new pipeline MLP; our share buyback program continues; and we expect the sale of Power to close during November,” Malcolm said.

Business Segment Performance

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

Consolidated Segment Profit (Loss)
Amounts in millions


	3Q						YTD
	2007			2006			2007			2006
Exploration & Production	$	168.5		$	144.5		$	566.0		$	411.9
Midstream	$	299.9		$	222.5		$	704.6		$	508.2
Gas Pipeline	$	182.9		$	109.0		$	512.9		$	366.4

	$	651.3		$	476.0		$	1,783.5		$	1,286.5

Gas Marketing	$	(66.8	)	$	(75.7	)	$	(160.1	)	$	(165.0	)
Other	$	0.4		$	(3.4	)	$	0.3		$	(10.2	)

Consolidated Segment Profit	$	584.9		$	396.9		$	1,623.7		$	1,111.3



Williams (NYSE: WMB) 3Q 2007 Financial Results — Nov. 1, 2007		Page 3 of 11

Recurring Consolidated Segment Profit (Loss)
After Mark-to-Market Adjustments*
Amounts in millions


	3Q						YTD
	2007			2006			2007			2006
Exploration & Production	$	168.5		$	144.5		$	566.0		$	411.9
Midstream	$	299.9		$	232.8		$	696.7		$	580.2
Gas Pipeline	$	170.7		$	109.0		$	478.1		$	364.4

	$	639.1		$	486.3		$	1,740.8		$	1,356.5

Gas Marketing	$	(66.8	)	$	(75.7	)	$	(160.1	)	$	(165.0	)
MTM Adjustments for Gas Marketing	$	32.0		$	68.5		$	139.5		$	160.5
Other	$	0.4		$	(3.4	)	$	0.3		$	(10.2	)

Recurring Consolidated Segment Profit After Mark-to-Market Adjustments	$	604.7		$	475.7		$	1,720.5		$	1,341.8


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

For third-quarter 2007, Williams’ businesses reported consolidated segment profit of $584.9 million, compared with $396.9 million for third-quarter 2006.

Year-to-date through Sept. 30, Williams’ businesses reported consolidated segment profit of $1.6 billion, compared to $1.1 billion for the same period in 2006.

The improvement in consolidated segment profit in the third quarter and first nine months of 2007 was primarily because of significant improvements in segment profit for Midstream, Exploration & Production and Gas Pipeline, driven by strong operating results.

On a basis adjusted to remove the effect of nonrecurring items and mark-to-market accounting, Williams reported recurring consolidated segment profit of $604.7 million for third-quarter 2007, compared with $475.7 million for third-quarter 2006, an increase of 27 percent.

For the year-to-date on the same basis, Williams’ recurring consolidated segment profit was $1.7 billion, compared to $1.3 billion for the same period in 2006, an increase of 28 percent.

Exploration & Production: Segment Profit Up 17 Percent on Sustained Production Increases

Exploration & Production, which includes natural gas production and development in the U.S. Rocky Mountains, San Juan Basin and Mid-Continent, and oil and gas development in South America, reported third-quarter 2007 segment profit of $168.5 million, a 17 percent increase over the $144.5 million reported for the same period in 2006.

For the first nine months of 2007, E&P reported segment profit of $566 million, compared to $411.9 million for the same period last year – a 37 percent increase.

The increase in third-quarter and year-to-date 2007 segment profit was driven primarily by continued



Williams (NYSE: WMB) 3Q 2007 Financial Results — Nov. 1, 2007		Page 4 of 11

strong growth in natural gas production volumes, along with higher net realized average natural gas prices. Higher operating expenses, primarily due to increased production volumes, partially offset these benefits.

For third-quarter 2007, combined average daily production from U.S. and international interests was up 17 percent to approximately 974 million cubic feet (MMcfe) of gas equivalent, compared with 831 MMcfe for the same period in 2006.

Daily production solely from interests in the United States was approximately 926 MMcfe in third-quarter 2007, up from 780 MMcfe in third-quarter 2006.

In the Piceance Basin of western Colorado — the company’s cornerstone for production and reserves growth – third-quarter 2007 average daily net production was 570 MMcfe per day – a 33 percent increase over the third-quarter 2006 level of 430 MMcfe.

During the third quarter of 2007, Williams’ U.S. production realized net average prices of $4.59 per thousand cubic feet (Mcfe) of gas equivalent, 7 percent higher than the $4.30 per Mcfe realized in the same period a year ago.

While basin prices were lower in third-quarter 2007 compared to the same period a year ago, the company’s firm transportation contracts, which allow a significant portion of its Rockies production to be sold at more advantageous market points, as well as fixed priced hedges and collars, contributed to the increase in net realized prices. Net realized average prices include market prices, net of fuel and shrink and hedge positions, less gathering and transportation expenses.

Williams is updating its 2007 segment profit guidance for Exploration & Production to $750 million to $825 million. Previous guidance was $750 million to $950 million. The company is updating the guidance due to lower than planned basin gas prices in the third quarter and also lower than expected basin gas prices in the fourth quarter.

Williams is increasing its 2008 segment profit guidance for Exploration & Production to $1 billion to $1.3 billion from $950 million to $1.25 billion. Higher expected net realized prices and production volumes, partially offset by higher costs, are the factors driving the increase.

The company is also increasing its capital expenditure guidance for Exploration & Production for both 2007 and 2008.

For 2007, the new range is $1.5 billion to $1.6 billion, up from $1.4 billion to $1.5 billion. For 2008, the new range is $1.4 billion to $1.6 billion. Previous guidance was $1.25 billion to $1.4 billion. Both new ranges reflect increased expected drilling activity, facilities and costs.

Midstream Gas & Liquids: NGL Margins Remain at Historic Levels, Drive Segment Profit

Midstream, which provides natural gas gathering and processing services, along with natural gas liquids fractionation and storage services and olefins production, reported third-quarter 2007 segment profit of $299.9 million, compared to $222.5 million in the third quarter of 2006 – an increase of 35 percent.



Williams (NYSE: WMB) 3Q 2007 Financial Results — Nov. 1, 2007		Page 5 of 11

For the first nine months of 2007, Midstream reported segment profit of $704.6 million, compared with $508.2 million for the same period in 2006 – an increase of 39 percent.

Midstream’s growth in segment profit during 2007 is primarily due to record-level NGL margins driven by low natural gas prices in the West region and favorable market commodity pricing on NGLs.

Higher volumes related to the February 2007 start-up of the fifth cryogenic gas processing train at the Opal, Wyo., complex also helped drive the growth in segment profit. The year-to-date period also benefited from the absence of a non-recurring charge of $70.4 million related to Gulf Liquids litigation that occurred during the 2006 period. Production declines in deepwater Gulf of Mexico contributed to lower gathering and production handling volumes, which partially offset these benefits.

Williams markets NGLs via equity volumes the company retains as payment-in-kind under certain processing contracts.

In third-quarter 2007, Midstream sold 358.1 million gallons of NGL equity volumes, compared with sales of 334.0 million gallons in the prior-year period.

Higher NGL sales volumes in the West, due to the new processing train at the Opal plant were partially offset by declining producers’ volumes in the Gulf Coast region.

For the first nine months of 2007, Midstream sold 1.06 billion gallons of NGL equity volumes, compared to 1.03 billion gallons sold during the first nine months of 2006.

Williams is once again increasing its segment profit guidance for Midstream for 2007 and 2008.

For 2007, the company now expects $950 million to $1.125 billion in segment profit; previous 2007 guidance was $700 million to $850 million. The primary drivers for the improved segment profit guidance are third-quarter performance and higher expected NGL prices.

For 2008, segment profit guidance is now $575 million to $850 million, up from previous guidance of $550 million to $825 million. The increase is based on higher NGL margins, partially offset by increased costs.

Williams is also increasing Midstream’s capital expenditure guidance for 2008. The company now expects $650 million to $700 million in capital expenditures – up from $525 million to $575 million.

The new capital range for 2008 reflects an expanded Perdido Norte project, as well as a variety of new projects in the rapidly expanding Western region.

Gas Pipeline: New Rates Continue to Drive Higher Segment Profit

Gas Pipeline, which primarily delivers natural gas to markets along the Eastern Seaboard, the Northwest, and Florida, reported third-quarter 2007 segment profit of $182.9 million, compared with $109.0 million for third-quarter 2006.

Year-to-date through Sept. 30, Gas Pipeline reported segment profit of $512.9 million, compared with $366.4 million for the same period last year.

The 68 percent increase in quarterly segment profit and 40 percent increase in year-to-date segment profit were primarily a result of increased revenues from new rates on both the Northwest Pipeline and Transco systems,



Williams (NYSE: WMB) 3Q 2007 Financial Results — Nov. 1, 2007		Page 6 of 11

increased earnings from the company’s 50 percent interest in Gulfstream Natural Gas Systems, and lower selling, general and administrative expenses. Higher depreciation expenses and operating costs partially offset these benefits.

The 2007 year-to-date results also include the benefit of a $16.6 million reduction to a regulatory liability and income of $18.2 million associated with payments received for a terminated firm transportation agreement on the Gray’s Harbor lateral. Of the latter amount, $12.2 million is reflected in the third quarter 2007 segment profit.

Northwest Pipeline’s new, higher rates went into effect on Jan. 1, 2007. Transco’s new, higher rates went into effect, subject to refund, on March 1, 2007. Final resolution of the Transco rate case is subject to the filing of a formal stipulation and agreement and subsequent approval by the FERC. The company expects to file the stipulation and agreement in the fourth quarter.

Williams is increasing its 2007 segment profit guidance for Gas Pipeline. The new 2007 segment profit guidance is $640 million to $670 million – up from $625 million to $655 million to reflect the favorable impact from the Gray’s Harbor lateral payments.

The company is also increasing its 2007 and 2008 capital expenditure guidance for Gas Pipeline. The new range for 2007 is $575 million to $625 million. The previous range was $460 million to $565 million. The new 2008 range is $360 million to $495 million, up from $285 million to $410 million. Both new ranges now include the contributions required for the ownership interest in Gulfstream.

Gas Marketing Services: Supporting Natural Gas Businesses with Marketing, Risk Management

Gas Marketing Services is responsible for supporting Williams’ natural gas businesses by providing marketing and risk management services. These services primarily include marketing and hedging the gas produced by Exploration & Production and procuring fuel and shrink gas for Midstream.

In addition, Gas Marketing manages various natural-gas related contracts, such as transportation, storage, and related hedges. The segment also manages certain legacy natural gas contracts and positions that previously were reported in the Power segment.

Gas Marketing’s results for the first nine months of 2007 reflect unrealized mark-to-market losses primarily caused by legacy natural gas contracts and positions. The company intends to liquidate a substantial portion of these legacy contracts.

Until the positions are liquidated, Gas Marketing’s earnings may continue to reflect mark-to-market volatility, as well as potential gains or losses associated with these positions.

Gas Marketing reported a third-quarter 2007 segment loss of $66.8 million, compared to a loss of $75.7 million in third-quarter 2006. For the first nine months of 2007, Gas Marketing reported a segment loss of $160.1 million, compared to a loss of $165 million in the 2006 period.



Williams (NYSE: WMB) 3Q 2007 Financial Results — Nov. 1, 2007		Page 7 of 11

Gas Marketing Recurring Segment Loss
Adjusted for Mark-to-Market Effect*
Amounts in millions


	3Q						YTD
	2007			2006			2007			2006
Segment loss	$	(66.8	)	$	(75.7	)	$	(160.1	)	$	(165.0	)
Nonrecurring adjustments		—			—			—			—

Recurring segment loss	$	(66.8	)	$	(75.7	)	$	(160.1	)	$	(165.0	)
Mark-to-market adjustments — net	$	32.0		$	68.5		$	139.5		$	160.5

Recurring segment loss after MTM adjustments	$	(34.8	)	$	(7.2	)	$	(20.6	)	$	(4.5	)


*		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 is updating its segment profit guidance for Gas Marketing for 2007 and 2008.

For 2007, the company now expects results to range from a loss of $150 million to a loss of $125 million, absent any future unrealized mark-to-market gains or losses. Previous guidance was a loss of $75 million to a loss of $50 million.

On a basis adjusted for the effect of mark-to-market accounting, Williams now expects segment results from a loss of $50 million to a loss of $25 million. Previous guidance for the adjusted results was breakeven to $25 million.

For 2008, Williams now expects Gas Marketing segment results to range from breakeven to a profit of $30 million, exclusive of the effect of mark-to-market adjustments and any gain or loss on the liquidation of legacy positions. Previous segment profit guidance for 2008 was $15 million to $55 million.

Guidance Through 2008

Guidance for consolidated segment profit includes results for Exploration & Production, Midstream and Gas Pipeline, as well as Gas Marketing and the Other segment. All consolidated segment profit and earnings per share ranges are presented on a recurring basis adjusted for the effect of mark-to-market accounting.

For 2007, Williams has increased its consolidated segment profit guidance to $2.35 billion to $2.50 billion and earnings per share of $1.60 to $1.70. Previous guidance was $2.14 billion to $2.40 billion and earnings per share of $1.30 to $1.50.

The new range for 2007 reflects previously referenced increases in Midstream, Exploration & Production and Gas Pipeline for the year.

The 2007 ranges assume unhedged natural gas prices ranging from $6.60 to $7.10 per Mcfe (Henry Hub), adjusted for basis differentials, NGL margins consistent with an oil-to-gas price ratio of 9.7 to 10.4 (West Texas Intermediate crude to Henry Hub gas), and an assumption for crude oil pricing in the range of $64 to $74 per barrel.



Williams (NYSE: WMB) 3Q 2007 Financial Results — Nov. 1, 2007		Page 8 of 11

Williams has also increased its previous guidance on capital expenditures for 2007. The updated range, which reflects previously referenced increases in Exploration & Production and Gas Pipeline is $2.8 billion to $2.95 billion; previous guidance was $2.58 billion to $2.78 billion.

For 2008, Williams has updated its consolidated segment profit guidance to $2.25 billion to $2.76 billion and has announced earnings per share of $1.50 to $1.90. Previous consolidated segment profit guidance was $2.09 billion to $2.81 billion. The company did not previously provide earnings per share guidance for 2008.

The new range for 2008 primarily reflects previously referenced updates in Exploration & Production and Midstream.

The 2008 ranges assume unhedged natural gas prices ranging from $7.05 to $8.35 per Mcfe (Henry Hub), adjusted for basis differentials, NGL margins consistent with an oil-to-gas price ratio of 8.5 to 9.6 (West Texas Intermediate crude to Henry Hub gas), and an assumption for crude oil pricing in the range of $60 to $80 per barrel.

Williams has also increased its previous guidance on capital expenditures for 2008. The updated range, which reflects previously referenced increases in Exploration & Production, Gas Pipeline and Midstream, is $2.48 billion to $2.83 billion; previous guidance was $2.13 billion to $2.4 billion.

Today’s Analyst Call

Williams’ management will discuss the company’s third-quarter 2007 financial results and outlook through 2008 during an analyst presentation to be webcast live beginning at 10 a.m. Eastern today. Participants are encouraged to access the presentation and corresponding slides via www.williams.com.

A limited number of phone lines also will be available at (877) 857-6149. International callers should dial (719) 325-4746. Callers should dial in at least 10 minutes prior to the start of the discussion. A replay of the webcast, in both streaming and downloadable podcast formats, will be available at www.williams.com for two weeks following the event.

Form 10-Q

The company expects to file its Form 10-Q with the Securities and Exchange Commission later today. 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 legacy wholesale power business that it has agreed to sell, with closing expected before the end of 2007. Williams’ operations are concentrated in the Pacific Northwest, Rocky Mountains, Gulf Coast, and Eastern Seaboard. More information is available at www.williams.com. Go to http://www.b2i.us/irpass.asp?BzID=630&to=ea&s=0 to join our e-mail list.



Williams (NYSE: WMB) 3Q 2007 Financial Results — Nov. 1, 2007		Page 9 of 11


Contact:		Jeff Pounds
		Williams (media relations)
		(918) 573-3332

		Travis Campbell
		Williams (investor relations)
		(918) 573-2944

		Richard George
		Williams (investor relations)
		(918) 573-3679

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

# # #

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

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 “unrisked theoretical resource estimates” that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated hydrocarbon 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. Generally under such techniques, probable reserve estimates are more than 50% certain and possible reserve estimates are less than 50% but more than 10% certain. Unrisked theoretical resource estimates are even less certain than those for possible reserves and are not risk adjusted. Unrisked theoretical resource estimates include (i) an estimate of hydrocarbon quantities for new areas for which we do not have



Williams (NYSE: WMB) 3Q 2007 Financial Results — Nov. 1, 2007		Page 10 of 11

sufficient information to date to classify the resources as probable or even possible reserves and (ii) the amount by which we have reduced our probable and possible reserves for existing areas to take into account the reduced level of certainty of recovery of the resources. Unlike probable and possible reserves, unrisked theoretical resource estimates do not take into account the uncertainty of resource recovery and, therefore, are not indicative of the expected future recovery and should not be relied upon.

Reference to “Resource Potential” includes proved, probable and possible reserves as well as unrisked theoretical resource estimates that might never be recoverable and are contingent on exploration success, technical improvements in drilling access, commerciality and other factors.

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 Feb. 28, 2007, and our quarterly reports on Form 10-Q available from our offices or from our website at www.williams.com.



Williams (NYSE: WMB) 3Q 2007 Financial Results — Nov. 1, 2007		Page 11 of 11

Financial Highlights and Operatings Statistics
(UNAUDITED)

Final

September 30, 2007

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


	2006															2007
(Dollars in millions, except per-share amounts)	1st Qtr*			2nd Qtr*			3rd Qtr*			4th Qtr*			Year*			1st Qtr			2nd Qtr			3rd Qtr			Year
Income (loss) from continuing operations available to common stockholders	$	132.0		$	(59.0	)	$	112.9		$	161.1		$	347.0		$	169.7		$	243.9		$	227.9		$	641.5



Income (loss) from continuing operations — diluted earnings (loss) per common share	$	0.22		$	(0.10	)	$	0.19		$	0.26		$	0.57		$	0.28		$	0.40		$	0.38		$	1.05



Nonrecurring items:


Gas Pipeline
Reversal of litigation contigency due to favorable ruling — TGPL	$	(2.0	)	$	—		$	—		$	—		$	(2.0	)	$	—		$	—		$	—		$	—
Change in estimate related to a regulatory liability — NWP		—			—			—			—			—			—			(16.6	)		—			(16.6	)
Contract termination gain related to Grays Harbor — NWP		—			—			—			—			—			—			(6.0	)		(12.2	)		(18.2	)

Total Gas Pipeline nonrecurring items		(2.0	)		—			—			—			(2.0	)		—			(22.6	)		(12.2	)		(34.8	)


Midstream Gas & Liquids
Reversal of a maintenance accrual		—			—			—			—			—			(7.9	)		—			—			(7.9	)
Gains on sales of MGL properties		—			—			(7.9	)		—			(7.9	)		—			—			—			—
Adjustment of accounts payable accrual		—			—			10.6			—			10.6			—			—			—			—
Losses on asset retirements, abandonments and write-downs		—			—			5.2			—			5.2			—			—			—			—
Accrual for Gulf Liquids litigation contingency		—			68.0			2.4			2.3			72.7			—			—			—			—
Settlement of an international contract dispute⁽¹⁾		(6.3	)		—			—			—			(6.3	)		—			—			—			—

Total Midstream Gas & Liquids nonrecurring items		(6.3	)		68.0			10.3			2.3			74.3			(7.9	)		—			—			(7.9	)


Nonrecurring items included in segment profit (loss)		(8.3	)		68.0			10.3			2.3			72.3			(7.9	)		(22.6	)		(12.2	)		(42.7	)


Nonrecurring items below segment profit (loss)
Impairment of cost-based investment — Petrowayu (Investing income / loss — Exploration & Production)⁽¹⁾		—			—			—			16.4			16.4			—			—			—			—
Securities litigation settlement and related costs ⁽²⁾		1.2			160.7			3.4			2.0			167.3			—			—			—			—
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)⁽¹⁾		27.0			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			0.6			1.4			22.0			1.4			1.2			0.6			3.2
Interest income related to contract termination gain noted above (Intvesting income — Gas Pipeline — NWP)		—			—			—			—			—			—			—			(2.3	)		(2.3	)

		16.5			185.1			4.0			19.8			225.4			1.4			1.2			(1.7	)		0.9


Total nonrecurring items		8.2			253.1			14.3			22.1			297.7			(6.5	)		(21.4	)		(13.9	)		(41.8	)
Tax effect for above items ⁽¹⁾⁽²⁾		3.4			76.6			5.3			2.3			87.6			(2.5	)		1.0			(5.3	)		(6.8	)
Adjustment for nonrecurring excess deferred tax provision		—			—			—			7.4			7.4			—			—			—			—
Adjustment for tax benefit related to federal income tax litigation		—			—			—			(25.1	)		(25.1	)		—			—			—			—


Recurring income from continuing operations available to common stockholders	$	136.8		$	117.5		$	121.9		$	163.2		$	539.4		$	165.7		$	221.5		$	219.3		$	606.5



Recurring diluted earnings per common share	$	0.23		$	0.20		$	0.20		$	0.27		$	0.89		$	0.27		$	0.36		$	0.36		$	0.99


Weighted-average shares — diluted (thousands)		607,073			595,561			609,062			610,352			608,627			611,470			613,172			610,651			611,761


⁽¹⁾		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 early debt retirement costs related to our convertible debt. The tax rate applied to 4th quarter 2006 has also been adjusted for the effect of a nondeductible international impairment.

⁽²⁾		The tax rate applied to nonrecurring items for 2nd, 3rd and 4th quarters 2006 has been adjusted for the effect of nondeductible expenses associated with securities litigation settlement and related costs. The tax rate applied to nonrecurring items for 2nd quarter 2007 has been adjusted to reverse the effect of certain of these previous adjustments as these expenses are now considered deductible based on an IRS ruling.

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.

*		Amounts have been recast to present certain operations as discontinued operations.

Consolidated Statement of Income
(UNAUDITED)


	2006															2007
(Dollars in millions, except per-share amounts)	1st Qtr *			2nd Qtr*			3rd Qtr*			4th Qtr*			Year*			1st Qtr			2nd Qtr			3rd Qtr			Year
Revenues	$	2,387.1		$	2,219.7		$	2,511.8		$	2,257.8		$	9,376.4		$	2,368.3		$	2,823.4		$	2,860.1		$	8,051.8

Segment costs and expenses:
Costs and operating expenses		1,962.2			1,777.1			2,039.6			1,787.5			7,566.4			1,843.3			2,180.2			2,221.3			6,244.8
Selling, general and administrative expenses		57.8			95.8			113.0			122.7			389.3			102.5			107.0			107.8			317.3
Other (income) expense — net		(21.6	)		65.9			(7.3	)		(3.7	)		33.3			(17.9	)		(18.0	)		(2.5	)		(38.4	)

Total segment costs and expenses		1,998.4			1,938.8			2,145.3			1,906.5			7,989.0			1,927.9			2,269.2			2,326.6			6,523.7


Equity earnings		22.2			23.1			29.9			23.7			98.9			21.4			22.8			51.4			95.6
Income (loss) from investments		—			(0.5	)		0.5			—			—			—			—			—			—

Total segment profit		410.9			303.5			396.9			375.0			1,486.3			461.8			577.0			584.9			1,623.7


Reclass equity earnings		(22.2	)		(23.1	)		(29.9	)		(23.7	)		(98.9	)		(21.4	)		(22.8	)		(51.4	)		(95.6	)
Reclass income (loss) from investments		—			0.5			(0.5	)		—			—			—			—			—			—
General corporate expenses		(30.6	)		(33.7	)		(35.0	)		(32.8	)		(132.1	)		(39.4	)		(36.2	)		(40.2	)		(115.8	)
Securities litigation settlement and related fees		(1.2	)		(160.7	)		(3.4	)		(2.0	)		(167.3	)		—			—			—			—

Operating income		356.9			86.5			328.1			316.5			1,088.0			401.0			518.0			493.3			1,412.3

Interest accrued		(161.3	)		(179.9	)		(161.0	)		(167.6	)		(669.8	)		(172.0	)		(172.1	)		(170.8	)		(514.9	)
Interest capitalized		3.0			4.0			4.8			5.4			17.2			4.9			6.7			9.2			20.8
Investing income		47.7			39.1			51.1			29.7			167.6			52.4			65.5			77.8			195.7
Early debt retirement costs		(27.0	)		(4.4	)		—			—			(31.4	)		—			—			—			—
Minority interest in income of consolidated subsidiaries		(7.1	)		(8.3	)		(12.1	)		(12.5	)		(40.0	)		(14.0	)		(25.4	)		(28.3	)		(67.7	)
Other income — net		8.0			8.2			2.6			7.5			26.3			2.0			3.3			6.9			12.2

Income (loss) from continuing operations before income taxes		220.2			(54.8	)		213.5			179.0			557.9			274.3			396.0			388.1			1,058.4
Provision for income taxes		88.2			4.2			100.6			17.9			210.9			104.6			152.1			160.2			416.9


Income (loss) from continuing operations		132.0			(59.0	)		112.9			161.1			347.0			169.7			243.9			227.9			641.5
Income (loss) from discontinued operations		(0.1	)		(17.0	)		(6.7	)		(14.7	)		(38.5	)		(35.7	)		189.2			(29.9	)		123.6


Net income (loss)	$	131.9		$	(76.0	)	$	106.2		$	146.4		$	308.5		$	134.0		$	433.1		$	198.0		$	765.1


Diluted earnings per common share:
Income (loss) from continuing operations	$	0.22		$	(0.10	)	$	0.19		$	0.26		$	0.57		$	0.28		$	0.40		$	0.38		$	1.05
Income (loss) from discontinued operations		—			(0.03	)		(0.01	)		(0.02	)		(0.06	)		(0.06	)		0.31			(0.05	)		0.20


Net income (loss)	$	0.22		$	(0.13	)	$	0.18		$	0.24		$	0.51		$	0.22		$	0.71		$	0.33		$	1.25


Weighted-average number of shares used in computation (thousands)		607,073			595,561			609,062			610,352			608,627			611,470			613,172			610,651			611,761

Common shares outstanding at end of period (thousands)		595,007			595,562			596,130			597,147			597,147			598,492			599,781			593,016			593,016

Market price per common share (end of period)	$	21.39		$	23.36		$	23.87		$	26.12		$	26.12		$	28.46		$	31.62		$	34.06		$	34.06

Common dividends per share	$	0.075		$	0.09		$	0.09		$	0.09		$	0.345		$	0.09		$	0.10		$	0.10		$	0.29


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.

*		Amounts have been recast to present certain operations as discontinued operations.

Reconciliation of Segment Profit to Recurring Segment Profit
(UNAUDITED)


	2006															2007
(Dollars in millions)	1st Qtr*			2nd Qtr*			3rd Qtr*			4th Qtr*			Year*			1st Qtr			2nd Qtr			3rd Qtr			Year
Segment profit (loss):

Exploration & Production	$	147.6		$	119.8		$	144.5		$	139.6		$	551.5		$	188.1		$	209.4		$	168.5		$	566.0
Gas Pipeline		134.7			122.7			109.0			101.0			467.4			149.7			180.3	**		182.9			512.9
Midstream Gas & Liquids		154.3			131.4			222.5			166.8			675.0			154.1			250.6			299.9			704.6
Gas Marketing Services		(23.4	)		(65.9	)		(75.7	)		(29.8	)		(194.8	)		(29.8	)		(63.5	)		(66.8	)		(160.1	)
Other		(2.3	)		(4.5	)		(3.4	)		(2.6	)		(12.8	)		(0.3	)		0.2			0.4			0.3

Total segment profit	$	410.9		$	303.5		$	396.9		$	375.0		$	1,486.3		$	461.8		$	577.0		$	584.9		$	1,623.7


Nonrecurring adjustments:

Exploration & Production	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—
Gas Pipeline		(2.0	)		—			—			—			(2.0	)		—			(22.6	)**		(12.2	)		(34.8	)
Midstream Gas & Liquids		(6.3	)		68.0			10.3			2.3			74.3			(7.9	)		—			—			(7.9	)
Gas Marketing Services		—			—			—			—			—			—			—			—			—
Other		—			—			—			—			—			—			—			—			—

Total segment nonrecurring adjustments	$	(8.3	)	$	68.0		$	10.3		$	2.3		$	72.3		$	(7.9	)	$	(22.6	)	$	(12.2	)	$	(42.7	)


Recurring segment profit (loss):

Exploration & Production	$	147.6		$	119.8		$	144.5		$	139.6		$	551.5		$	188.1		$	209.4			168.5		$	566.0
Gas Pipeline		132.7			122.7			109.0			101.0			465.4			149.7			157.7			170.7			478.1
Midstream Gas & Liquids		148.0			199.4			232.8			169.1			749.3			146.2			250.6			299.9			696.7
Gas Marketing Services		(23.4	)		(65.9	)		(75.7	)		(29.8	)		(194.8	)		(29.8	)		(63.5	)		(66.8	)		(160.1	)
Other		(2.3	)		(4.5	)		(3.4	)		(2.6	)		(12.8	)		(0.3	)		0.2			0.4			0.3

Total recurring segment profit	$	402.6		$	371.5		$	407.2		$	377.3		$	1,558.6		$	453.9		$	554.4		$	572.7		$	1,581.0


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

*		Amounts have been recast to present certain operations as discontinued operations and to reflect other changes related to the sale of our power business.

**		Includes $6 million of income associated with payments received for a terminated firm transportation agreement on Gas Pipeline’s Grays Harbor lateral that was reclassified from other income — net below operating income to other (income) expense — net within segment costs and expenses.

Exploration & Production
(UNAUDITED)


	2006													2007
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr		Year		1st Qtr			2nd Qtr			3rd Qtr		Year
Revenues:
Production	$	286.8		$	287.9		$	316.1		$	347.0	$	1,237.8	$	413.2		$	448.3		$	399.2	$	1,260.7
Gas management		41.2			28.3			25.3			39.3		134.1		55.3			66.7			62.5		184.5
Net nonqualified hedge derivative income (loss)		12.8			(1.6	)		1.8			11.0		24.0		(2.2	)		(5.0	)		8.0		0.8
International		16.0			15.1			16.8			15.8		63.7		14.5			16.2			15.8		46.5
Other		(0.8	)		12.6			11.1			5.1		28.0		1.9			13.3			13.8		29.0

Total revenues		356.0			342.3			371.1			418.2		1,487.6		482.7			539.5			499.3		1,521.5

Segment costs and expenses:
Depreciation, depletion and amortization (including International)		73.1			84.5			95.3			108.6		361.5		113.6			131.5			138.6		383.7
Lease and other operating expenses		30.1			43.8			39.0			46.4		159.3		43.7			48.9			54.4		147.0
Operating taxes		31.8			28.1			31.1			28.7		119.7		33.5			35.8			29.2		98.5
Exploration expense		4.4			2.4			2.6			7.2		16.6		6.9			4.6			4.3		15.8
Third party gathering expense		6.4			7.5			7.6			8.6		30.1		8.6			7.6			8.4		24.6
Selling, general and administrative expenses (including International)		21.5			28.2			28.2			34.4		112.3		35.9			32.1			34.9		102.9
Gas management expenses		41.2			28.3			25.3			39.3		134.1		55.3			66.7			62.5		184.5
International (excluding DD&A and SG&A)		5.5			4.9			5.0			5.9		21.3		4.3			6.1			6.7		17.1
Other (income) expense — net		(0.6	)		0.7			(1.9	)		4.8		3.0		(1.9	)		1.7			1.9		1.7

Total segment costs and expenses		213.4			228.4			232.2			283.9		957.9		299.9			335.0			340.9		975.8

Equity earnings — International		5.0			5.9			5.6			5.3		21.8		5.3			4.9			10.1		20.3


Reported segment profit		147.6			119.8			144.5			139.6		551.5		188.1			209.4			168.5		566.0

Nonrecurring adjustments		—			—			—			—		—		—			—			—		—


Recurring segment profit	$	147.6		$	119.8		$	144.5		$	139.6	$	551.5	$	188.1		$	209.4		$	168.5	$	566.0

Operating statistics

Domestic:
Total domestic net volumes (Bcfe)		59.5			67.1			71.8			76.0		274.4		76.1			81.7			85.2		243.0
Net domestic volumes per day (MMcfe/d)		661			738			780			826		752		845			898			926		890
Net domestic realized price ($/Mcfe) (1)	$	4.712		$	4.177		$	4.300		$	4.450	$	4.401	$	5.318		$	5.390		$	4.587	$	5.086
Production taxes per Mcfe	$	0.534		$	0.420		$	0.433		$	0.377	$	0.436	$	0.440		$	0.439		$	0.343	$	0.405
Lease and other operating expense per Mcfe	$	0.505		$	0.653		$	0.544		$	0.610	$	0.581	$	0.574		$	0.598		$	0.639	$	0.605


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


International:
Total volumes including Equity Investee (Bcfe)	6.0	5.6	6.0	6.1	23.7	5.2	5.4	5.6	16.2
Volumes per day (MMcfe/d)	67	61	65	67	65	58	59	61	59
Volumes net to Williams (after minority interest) (Bcfe)	4.7	4.4	4.7	4.8	18.6	4.1	4.2	4.4	12.7
Volumes net to Williams per day (MMcfe/d)	53	48	51	53	51	46	46	48	47

Total Domestic and International:
Volumes net to Williams (after minority interest) (Bcfe)	64.2	71.5	76.5	80.9	293.1	80.2	85.9	89.7	255.8
Volumes net to Williams per day (MMcfe/d)	714	786	831	879	803	891	945	974	937

Gas Pipeline
(UNAUDITED)


	2006															2007
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr		2nd Qtr			3rd Qtr			Year
Revenues:
Northwest Pipeline	$	79.6		$	80.0		$	81.0		$	83.7		$	324.3		$	103.0	$	102.7		$	106.4		$	312.1
Transcontinental Gas Pipe Line		254.3			257.2			253.0			258.1			1,022.6			267.6		312.1			286.2			865.9
Other		0.1			0.1			0.2			0.4			0.8			0.2		—			0.2			0.4

Total revenues		334.0			337.3			334.2			342.2			1,347.7			370.8		414.8			392.8			1,178.4

Segment costs and expenses:
Costs and operating expenses		177.2			192.8			192.2			203.2			765.4			195.2		224.0			202.8			622.0
Selling, general and administrative expenses		31.0			35.4			45.1			50.0			161.5			34.8		38.5			36.4			109.7
Other (income) expense — net		(1.4	)		(3.4	)		(2.4	)		(2.3	)		(9.5	)		0.4		(18.7	)		(8.3	)		(26.6	)

Total segment costs and expenses		206.8			224.8			234.9			250.9			917.4			230.4		243.8			230.9			705.1

Equity earnings		7.5			10.7			9.2			9.7			37.1			9.3		9.3			21.0			39.6
Income (loss) from investments		—			(0.5	)		0.5			—			—			—		—			—			—


Reported segment profit:
Northwest Pipeline		33.3			32.8			31.8			29.0			126.9			54.9		74.9	*		66.4			196.2
Transcontinental Gas Pipe Line		95.8			81.3			69.5			63.7			310.3			87.1		97.8			97.0			281.9
Other		5.6			8.6			7.7			8.3			30.2			7.7		7.6			19.5			34.8

Total reported segment profit		134.7			122.7			109.0			101.0			467.4			149.7		180.3			182.9			512.9

Nonrecurring adjustments:
Northwest Pipeline		—			—			—			—			—			—		(22.6	)*		(12.2	)		(34.8	)
Transcontinental Gas Pipe Line		(2.0	)		—			—			—			(2.0	)		—		—			—			—
Other		—			—			—			—			—			—		—			—			—

Total nonrecurring adjustments		(2.0	)		—			—			—			(2.0	)		—		(22.6	)		(12.2	)		(34.8	)

Recurring segment profit:
Northwest Pipeline		33.3			32.8			31.8			29.0			126.9			54.9		52.3			54.2			161.4
Transcontinental Gas Pipe Line		93.8			81.3			69.5			63.7			308.3			87.1		97.8			97.0			281.9
Other		5.6			8.6			7.7			8.3			30.2			7.7		7.6			19.5			34.8

Total recurring segment profit	$	132.7		$	122.7		$	109.0		$	101.0		$	465.4		$	149.7	$	157.7		$	170.7		$	478.1


**		Includes $6 million of income associated with payments received for a terminated firm transportation agreement on Gas Pipeline’s Grays Harbor lateral that was reclassified from other income — net below operating income to other (income) expense — net within segment costs and expenses.


Operating statistics

Northwest Pipeline
Throughput (TBtu)	179.7	142.7	156.6	196.5	675.5	200.2	159.8	176.5	536.5
Average daily transportation volumes (TBtu)	2.0	1.6	1.7	2.1	1.9	2.2	1.8	1.9	2.0
Average daily firm reserved capacity (TBtu)	2.5	2.5	2.5	2.5	2.5	2.5	2.5	2.5	2.5

Transcontinental Gas Pipe Line
Throughput (TBtu)	502.8	427.0	471.3	457.7	1,858.8	525.2	427.6	477.4	1,430.2
Average daily transportation volumes (TBtu)	5.6	4.6	5.1	5.0	5.1	5.8	4.7	5.2	5.2
Average daily firm reserved capacity (TBtu)	7.0	6.4	6.4	6.7	6.6	6.8	6.4	6.4	6.5

Midstream Gas & Liquids
(UNAUDITED)


	2006															2007
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			Year

Revenues:
Gathering & Processing	$	101.7		$	106.4		$	106.8		$	108.9		$	423.8		$	104.0		$	101.6		$	106.5		$	312.1
Venezuela fee revenue		38.9			38.0			40.6			36.3			153.8			37.3			37.6			37.6			112.5
NGL sales from gas processing		263.7			292.6			296.6			262.9			1,115.8			260.0			318.7			346.4			925.1
Production handling and transportation		37.2			33.2			33.0			30.4			133.8			28.8			28.3			25.8			82.9
Olefins sales (including Gulf and Canada)		148.9			131.4			175.9			155.7			611.9			131.0			176.1			286.7			593.8
Trading/marketing sales		709.0			806.1			863.9			757.9			3,136.9			792.1			1,007.1			1,062.3			2,861.5
Other revenues		46.6			37.2			38.9			35.2			157.9			33.2			39.5			33.1			105.8

		1,346.0			1,444.9			1,555.7			1,387.3			5,733.9			1,386.4			1,708.9			1,898.4			4,993.7
Intrasegment eliminations		(354.4	)		(395.1	)		(428.7	)		(396.9	)		(1,575.1	)		(384.4	)		(466.3	)		(537.5	)		(1,388.2	)

Total revenues		991.6			1,049.8			1,127.0			990.4			4,158.8			1,002.0			1,242.6			1,360.9			3,605.5
Segment costs and expenses:
NGL cost of goods sold		199.9			172.7			156.9			144.8			674.3			165.5			149.6			124.0			439.1
Olefins cost of goods sold		132.8			108.1			141.2			127.8			509.9			114.2			147.0			238.7			499.9
Trading/marketing cost of goods sold		716.7			799.1			863.4			765.8			3,145.0			787.4			995.9			1,057.7			2,841.0
Venezuela operating costs		16.8			18.1			17.1			19.0			71.0			18.8			18.9			19.8			57.5
Operating costs		129.8			126.8			141.6			143.5			541.7			140.9			127.8			139.1			407.8
Other
Selling, general and administrative expenses		23.3			25.2			31.1			31.4			111.0			27.2			28.6			32.0			87.8
Other (income) expense — net		(17.9	)		70.0			(3.2	)		(2.9	)		46.0			(15.0	)		(0.8	)		7.5			(8.3	)
Intrasegment eliminations		(354.4	)		(395.1	)		(428.7	)		(396.9	)		(1,575.1	)		(384.4	)		(466.3	)		(537.5	)		(1,388.2	)

Total segment costs and expenses		847.0			924.9			919.4			832.5			3,523.8			854.6			1,000.7			1,081.3			2,936.6
Equity earnings		9.7			6.5			14.9			8.9			40.0			6.7			8.7			20.3			35.7
Income from investments		—			—			—			—			—			—			—			—			—

Reported segment profit		154.3			131.4			222.5			166.8			675.0			154.1			250.6			299.9			704.6
Nonrecurring adjustments		(6.3	)		68.0			10.3			2.3			74.3			(7.9	)		—			—			(7.9	)

Recurring segment profit	$	148.0		$	199.4		$	232.8		$	169.1		$	749.3		$	146.2		$	250.6		$	299.9		$	696.7


Operating statistics

Gathering volumes (TBtu)		296.9			300.1			292.5			291.9			1,181.4			269.3			258.4			266.3			794.0

Processing volumes (TBtu)		191.8			204.8			210.0			226.5			833.1			226.9			234.4			242.6			703.9

NGL equity sales (million gallons) *		333.7			361.3			334.0			325.8			1,354.8			344.6			359.7			358.1			1,062.4
NGL margin ($/gallon)	$	0.1900		$	0.3319		$	0.4183		$	0.3625		$	0.3259		$	0.2742		$	0.4701		$	0.6211		$	0.4575

Domestic NGL Production (million gallons) *		549.9			591.5			583.5			607.5			2,332.4			594.1			619.2			639.2			1,852.5
Olefins sales (Ethylene & Propylene) (million lbs)		259.2			196.8			268.1			263.8			987.9			213.4			273.4			473.2			960.0


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

Gas Marketing Services
(UNAUDITED)


	2006															2007
(Dollars in millions)	1st Qtr*			2nd Qtr*			3rd Qtr*			4th Qtr*			Year*			1st Qtr			2nd Qtr			3rd Qtr			Year

Revenues		1,424.0			1,116.7			1,320.6			1,187.3		$	5,048.6			1,288.3			1,393.4			1,246.9			3,928.6

Segment costs and expenses:
Costs and operating expenses		1,469.6			1,180.6			1,392.3			1,215.0			5,257.5			1,316.2			1,452.2			1,311.9			4,080.3
Selling, general and administrative expenses		(20.9	)		1.4			3.6			3.2			(12.7	)		1.9			4.7			1.8			8.4
Other (income) expense — net		(1.3	)		0.6			0.4			(1.1	)		(1.4	)		—			—			—			—

Total segment costs and expenses		1,447.4			1,182.6			1,396.3			1,217.1			5,243.4			1,318.1			1,456.9			1,313.7			4,088.7

Reported segment loss		(23.4	)		(65.9	)		(75.7	)		(29.8	)		(194.8	)		(29.8	)		(63.5	)		(66.8	)		(160.1	)

Nonrecurring adjustments		—			—			—			—			—			—			—			—			—


Recurring segment loss	$	(23.4	)	$	(65.9	)	$	(75.7	)	$	(29.8	)	$	(194.8	)	$	(29.8	)	$	(63.5	)	$	(66.8	)	$	(160.1	)


*		Amounts have been recast to present certain operations as discontinued operations.

Capital Expenditures and Investments
(UNAUDITED)


	2006													2007
(Dollars in millions)	1st Qtr			2nd Qtr		3rd Qtr			4th Qtr		Year			1st Qtr		2nd Qtr		3rd Qtr			Year

Capital expenditures:
Exploration & Production	$	310.3		$	283.9	$	384.9		$	442.9	$	1,422.0		$	342.5	$	386.6	$	466.9		$	1,196.0

Gas Pipeline:
Northwest Pipeline		40.3			96.0		177.4			159.1		472.8			49.3		20.4		37.2			106.9
Transcontinental Gas Pipe Line		46.4			106.7		109.4			75.6		338.1			59.0		118.8		139.2			317.0

Total		86.7			202.7		286.8			234.7		810.9			108.3		139.2		176.4			423.9

Midstream Gas & Liquids		70.7			39.3		83.5			63.5		257.0			54.8		185.3		226.4			466.5
Gas Marketing Services		0.6			0.6		(0.1	)		0.1		1.2			—		—		—			—
Other		—			7.8		1.2			9.1		18.1			3.5		6.4		3.6			13.5

Total	$	468.3		$	534.3	$	756.3		$	750.3	$	2,509.2		$	509.1	$	717.5	$	873.3		$	2,099.9


Purchase of investments:
Exploration & Production		—			—		—			—		—			—		—		(2.3	)		(2.3	)
Gas Pipeline		—			—		4.5			0.7		5.2			1.1		2.5		15.1			18.7
Midstream Gas & Liquids		(3.4	)		0.8		—			2.4		(0.2	)		—		—		—			—
Other		13.1			26.0		4.6			0.2		43.9			20.1		0.4		—			20.5

Total	$	9.7		$	26.8	$	9.1		$	3.3	$	48.9		$	21.2	$	2.9	$	12.8		$	36.9


Summary:
Exploration & Production	$	310.3		$	283.9	$	384.9		$	442.9	$	1,422.0		$	342.5	$	386.6	$	464.6		$	1,193.7
Gas Pipeline		86.7			202.7		291.3			235.4		816.1			109.4		141.7		191.5			442.6
Midstream Gas & Liquids		67.3			40.1		83.5			65.9		256.8			54.8		185.3		226.4			466.5
Gas Marketing Services		0.6			0.6		(0.1	)		0.1		1.2			—		—		—			—
Other		13.1			33.8		5.8			9.3		62.0			23.6		6.8		3.6			34.0

Total	$	478.0		$	561.1	$	765.4		$	753.6	$	2,558.1		$	530.3	$	720.4	$	886.1		$	2,136.8


Cumulative summary:
Exploration & Production	$	310.3		$	594.2	$	979.1		$	1,422.0	$	1,422.0		$	342.5	$	729.1	$	1,193.7		$	1,193.7
Gas Pipeline		86.7			289.4		580.7			816.1		816.1			109.4		251.1		442.6			442.6
Midstream Gas & Liquids		67.3			107.4		190.9			256.8		256.8			54.8		240.1		466.5			466.5
Gas Marketing Services		0.6			1.2		1.1			1.2		1.2			—		—		—			—
Other		13.1			46.9		52.7			62.0		62.0			23.6		30.4		34.0			34.0

Total	$	478.0		$	1,039.1	$	1,804.5		$	2,558.1	$	2,558.1		$	530.3	$	1,250.7	$	2,136.8		$	2,136.8

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


	2006															2007
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			Year

Depreciation, depletion and amortization:
Exploration & Production	$	73.0		$	84.2		$	94.8		$	108.2		$	360.2		$	113.6			131.3			138.8			383.7
Gas Pipeline:
Northwest Pipeline		18.5			18.8			19.1			20.2			76.6			23.4			21.1			21.4			65.9
Transcontinental Gas Pipe Line		50.0			51.7			51.2			52.2			205.1			53.9			58.0			58.0			169.9

Total		68.5			70.5			70.3			72.4			281.7			77.3			79.1			79.4			235.8
Midstream Gas & Liquids		49.8			50.3			50.3			52.4			202.8			53.1			54.1			52.0			159.2
Gas Marketing Services		1.9			1.9			1.1			0.8			5.7			1.0			1.0			2.0			4.0
Other		2.9			2.7			3.1			3.0			11.7			2.7			2.9			2.9			8.5

Total	$	196.1		$	209.6		$	219.6		$	236.8		$	862.1		$	247.7		$	268.4		$	275.1		$	791.2


Other selected financial data:
Cash and cash equivalents	$	1,115.0		$	980.4		$	1,074.6		$	2,268.6		$	2,268.6		$	1,811.2		$	1,739.0		$	1,455.4		$	1,455.4

Total assets	$	26,029.0		$	25,617.2		$	24,821.5		$	25,402.4		$	25,402.4		$	25,936.0		$	26,046.1		$	25,836.7		$	25,836.7

Capital structure:
Debt
Current	$	175.7		$	170.7		$	142.3		$	392.1		$	392.1		$	387.7		$	468.1		$	465.6		$	465.6
Noncurrent	$	7,252.8		$	7,292.6		$	7,275.2		$	7,622.0		$	7,622.0		$	7,507.5		$	7,443.2		$	7,424.6		$	7,424.6
Stockholders’ equity	$	5,925.5		$	5,882.3		$	6,071.2		$	6,073.2		$	6,073.2		$	6,191.7		$	6,423.3		$	6,455.6		$	6,455.6
Debt to debt-plus-equity ratio		55.6	%		55.9	%		55.0	%		56.9	%		56.9	%		56.0	%		55.2	%		55.0	%		55.0	%

Non-GAAP Utility Statement:

This press release includes certain financial measures, EBITDA, recurring earnings, operating 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. Operating free cash flow is defined as cash flow from continuing operations less capital expenditures before dividends or principal payments. Recurring earnings exclude items of income or loss that the company characterizes as unrepresentative of its ongoing 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, operating 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 Gas Marketing Services mark-to-market adjustments. This press release is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Management uses the mark-to-market adjustments to better reflect Gas Marketing’s results on a basis that is more consistent with Gas Marketing’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 derivative assets and liabilities 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 Gas Marketing segment but does not substitute for actual cash flows. We also apply the mark-to-market adjustment and the recurring adjustments to present a measure referred to as recurring income from continuing operations after mark-to-market adjustments.

Adjustment to remove MTM effect

Dollars in millions except for per share amounts


	3rd Quarter						YTD
	2007			2006			2007			2006
Recurring income from cont. ops available to common shareholders	$	219		$	122		$	607		$	376
Recurring diluted earnings per common share	$	0.36		$	0.20		$	0.99		$	0.62

Mark-to-Market (MTM) adjustments:
Reverse forward unrealized MTM losses		54			52			156			113
Add realized gains (losses) from MTM previously recognized		(22	)		16			(16	)		47

Total MTM adjustments		32			68			140			160

Tax effect of total MTM adjustments		(12	)		(26	)		(54	)		(61	)


After tax MTM adjustments		20			42			86			99

Recurring income from cont. ops available to common shareholders after MTM adjust	$	239		$	164		$	693		$	475
Recurring diluted earnings per share after MTM adj	$	0.39		$	0.27		$	1.14		$	0.79

weighted average shares — diluted (thousands)		613,172			595,561			612,325			598,634

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.

Some annual figures may differ from sum of quarterly figures due to rounding.

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


	2006															2007
Dollars in millions, except per-share amounts)	1st Qtr*			2nd Qtr*			3rd Qtr*			4th Qtr*			Year*			1st Qtr			2nd Qtr			3rd Qtr			Year

Income (loss) from continuing operations available to common stockholders	$	132.0			($59.0	)	$	112.9		$	161.1		$	347.0		$	169.7		$	243.9		$	227.9		$	641.5


Income (loss) from continuing operations — diluted earnings (loss) per common share	$	0.22			($0.10	)	$	0.19		$	0.26		$	0.57		$	0.28		$	0.40		$	0.38		$	1.05


Nonrecurring items:

Gas Pipeline
Reversal of litigation contigency due to favorable ruling — TGPL	$	(2.0	)	$	—		$	—		$	—		$	(2.0	)	$	—		$	—		$	—		$	—
Change in estimate related to a regulatory liability — NWP		—			—			—			—			—			—			(16.6	)		—			(16.6	)
Contract termination gain related to Grays Harbor — NWP		—			—			—			—			—			—			(6.0	)		(12.2	)		(18.2	)

Total Gas Pipeline nonrecurring items		(2.0	)		—			—			—			(2.0	)		—			(22.6	)		(12.2	)		(34.8	)

Midstream Gas & Liquids
Reversal of a maintenance accrual		—			—			—			—			—			(7.9	)		—			—			(7.9	)
Gains on sales of MGL properties		—			—			(7.9	)		—			(7.9	)		—			—			—			—
Adjustment of accounts payable accrual		—			—			10.6			—			10.6			—			—			—			—
Losses on asset retirements, abandonments and write-downs		—			—			5.2			—			5.2			—			—			—			—
Accrual for Gulf Liquids litigation contingency		—			68.0			2.4			2.3			72.7			—			—			—			—
Settlement of an international contract dispute⁽¹⁾		(6.3	)		—			—			—			(6.3	)		—			—			—			—

Total Midstream Gas & Liquids nonrecurring items		(6.3	)		68.0			10.3			2.3			74.3			(7.9	)		—			—			(7.9	)



Nonrecurring items included in segment profit (loss)		(8.3	)		68.0			10.3			2.3			72.3			(7.9	)		(22.6	)		(12.2	)		(42.7	)

Nonrecurring items below segment profit (loss)
Impairment of cost-based investment — Petrowayu (Investing income / loss — Exploration & Production)⁽¹⁾		—			—			—			16.4			16.4			—			—			—			—
Securities litigation settlement and related costs ⁽²⁾		1.2			160.7			3.4			2.0			167.3			—			—			—			—
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)⁽¹⁾		27.0			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			0.6			1.4			22.0			1.4			1.2			0.6			3.2
Interest income related to contract termination gain noted above (Intvesting income — Gas Pipeline — NWP)		—			—			—			—			—			—			—			(2.3	)		(2.3	)

		16.5			185.1			4.0			19.8			225.4			1.4			1.2			(1.7	)		0.9

Total nonrecurring items		8.2			253.1			14.3			22.1			297.7			(6.5	)		(21.4	)		(13.9	)		(41.8	)
Tax effect for above items ⁽¹⁾⁽²⁾		3.4			76.6			5.3			2.3			87.6			(2.5	)		1.0			(5.3	)		(6.8	)
Adjustment for nonrecurring excess deferred tax provision		—			—			—			7.4			7.4			—			—			—			—
Adjustment for tax benefit related to federal income tax litigation		—			—			—			(25.1	)		(25.1	)		—			—			—			—


Recurring income from continuing operations available to common stockholders	$	136.8		$	117.5		$	121.9		$	163.2		$	539.4		$	165.7		$	221.5		$	219.3		$	606.5


Recurring diluted earnings per common share	$	0.23		$	0.20		$	0.20		$	0.27		$	0.89		$	0.27		$	0.36		$	0.36		$	0.99


Weighted-average shares — diluted (thousands)		607,073			595,561			609,062			610,352			608,627			611,470			613,172			610,651			611,761


⁽¹⁾		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 early debt retirement costs related to our convertible debt. The tax rate applied to 4th quarter 2006 has also been adjusted for the effect of a nondeductible international impairment.

⁽²⁾		The tax rate applied to nonrecurring items for 2nd, 3rd and 4th quarters 2006 has been adjusted for the effect of nondeductible expenses associated with securities litigation settlement and related costs. The tax rate applied to nonrecurring items for 2nd quarter 2007 has been adjusted to reverse the effect of certain of these previous adjustments as these expenses are now considered deductible based on an IRS ruling.

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.

*		Amounts have been recast to present certain operations as discontinued operations.