exv99w1

Exhibit 99.1




News Release

NYSE: WMB

Date: Nov. 2, 2006

Williams Reports Third-Quarter 2006 Financial Results

	•		3Q Net Income Up Significantly

	•		Company Raises Earnings Guidance Again for 2006

	•		38% Increase in 3Q Recurring Adjusted Income; 48% Increase YTD by Same Measure

	•		Natural Gas Production Up 22%; Surpasses 800 MMcfe Per Day

	•		NGL Margins 112% Higher Than 3Q 2005


Quarterly Summary Information	3Q 2006						3Q 2005
Per share amounts are reported on a diluted basis	millions			per share			millions			per share
Income from continuing operations	$	110.1		$	0.19		$	5.7		$	0.01

Loss from discontinued operations	$	(3.9	)	$	(0.01	)	$	(1.3	)	$	0.00


Net income	$	106.2		$	0.18		$	4.4		$	0.01


Recurring income (loss) from continuing operations*	$	113.4		$	0.19		$	(4.6	)	$	(0.01	)

After-tax mark-to-market adjustments	$	59.0		$	0.09		$	129.9		$	0.23


Recurring income from continuing operations — after mark-to-market adjustment*	$	172.4		$	0.28		$	125.3		$	0.22

TULSA, Okla. — Williams (NYSE:WMB) today announced third-quarter 2006 unaudited net income of $106.2 million, or 18 cents per share on a diluted basis, compared with net income of $4.4 million, or 1 cent per share, for third-quarter 2005.


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	$	177.3		$	0.29		$	248.6		$	0.42

Loss from discontinued operations	$	(15.2	)	$	(0.02	)	$	(1.8	)	$	0.00


Net income	$	162.1		$	0.27		$	246.8		$	0.42


Recurring income from continuing operations*	$	361.9		$	0.60		$	259.7		$	0.44

After-tax mark-to-market adjustments	$	165.5		$	0.27		$	97.6		$	0.16


Recurring income from continuing operations — after mark-to-market adjustment*	$	527.4		$	0.87		$	357.3		$	0.60


*		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 — 3rd Quarter Results — Nov. 2, 2006 — Page 1 of 11

Third-quarter 2006 benefited from a 112 percent increase in natural gas liquids (NGL) sales margins, 22 percent higher natural gas production volumes, and significantly lower levels of forward unrealized mark-to-market losses. These benefits were partially offset by higher operating and maintenance costs.

Year-to-date through Sept. 30, Williams reported net income of $162.1 million, or 27 cents per share on a diluted basis, compared with net income of $246.8 million, or 42 cents per share, for the same period in 2005.

Results for the first nine months of 2006 are significantly reduced by the after-tax impact of legacy litigation charges recorded in the second quarter totaling approximately $175 million.

While these nonrecurring charges obscure the company’s strong performance overall in 2006, Williams has realized significantly higher NGL sales margins and continues to rapidly increase its natural gas production in the western United States. Production in the Piceance Basin – the company’s cornerstone property for production growth – increased 31 percent year-over-year in the third quarter.

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 derivatives – increased 38 percent from a year ago to $172.4 million, or 28 cents per share, in third-quarter 2006 from $125.3 million, or 22 cents per share in third-quarter 2005.

Year-to-date through Sept. 30, recurring income from continuing operations – adjusted to remove the effect of mark-to-market accounting – was $527.4 million, or 87 cents per share, an increase of 48 percent compared with $357.3 million, or 60 cents per share, for the same period in 2005.

The quarterly and year-to-date improvement is primarily the result of higher NGL sales margins; increased natural gas production, particularly in the Piceance and Powder River basins; increased gathering and processing revenue; and improved results in the power portfolio.

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 Again

Williams has raised its guidance for 2006 based on the company’s strong operating performance through three quarters, anticipated increases in natural gas production volumes, and its outlook for energy commodity prices — key factors that have driven higher sales margins for natural gas liquids.

Williams — 3rd Quarter Results — Nov. 2, 2006 — Page 2 of 11

The company now expects $1.05 to $1.20 for diluted earnings per share in 2006 on a recurring basis adjusted to remove the effect of mark-to-market accounting, compared with the previous expectation of 95 cents to $1.20.

Williams also is raising its expectations for 2006 consolidated segment profit on a recurring basis adjusted to remove the effect of mark-to-market accounting. The company now expects approximately $1.8 billion to $2.02 billion for this measure. Williams previously expected $1.69 billion to $2.01 billion.

Williams also modified its expected capital budget for 2006 through 2008. The increase in planned capital spending for 2007 and 2008 is for Midstream growth projects – primarily in the western deepwater Gulf of Mexico – that are expected to provide attractive returns on investment.


Updated Cap-Ex Guidance
	NEW	PREVIOUS
2006	$2.175 billion - $2.375 billion	$2.2 billion - $2.4 billion

2007	$2 billion - $2.2 billion	$1.775 billion -$1.975 billion

2008	$1.8 billion - $2.05 billion	$1.575 billion-$1.825 billion

CEO Perspective

“This is the second time we’ve raised our earnings guidance this year,” said Steve Malcolm, Williams’ chairman, president and chief executive officer. “And we like the momentum we have going into 2007 and beyond.”

“Our outlook is based on the fact that our natural gas production continues to rapidly climb, our older below-market hedges for that production are beginning to roll off, we see sustained strength in NGL sales margins, and our Midstream business has sizeable opportunities on the horizon.

“As we’ve shown, we’re poised to capture value creation with diligence, determination and fiscal discipline. Our businesses offer unique capabilities that our customers value. Our assets are strategically located in areas where we can capture meaningful growth. The scale of our operations gives us competitive advantages. And our liquidity and cash flow remain very robust.

“Overall, our portfolio of businesses is performing extremely well. Our business diversity is designed to help us do well in different price environments. We have a great deal of balance that is evidenced in our revenue streams.

“This year is a perfect example. Our Midstream business has provided a natural hedge to the price exposure we have in Exploration & Production. So while natural gas prices have been lower, the NGL margins in Midstream have been higher – significantly higher.”

Business Segment Performance: Substantial Increase in 3Q Segment Profit

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 — 3rd Quarter Results — Nov. 2, 2006 — Page 3 of 11


Recurring Segment Profit Adjusted for Mark-to-Market Effect	3Q					YTD
Amounts are reported in millions	2006		2005			2006		2005
Segment profit	$	395.8	$	204.5		$	1,101.0	$	970.6

Nonrecurring adjustments	$	1.1	$	(35.5	)	$	60.8	$	(0.3	)


Recurring segment profit	$	396.9	$	169.0		$	1,161.8	$	970.3

Reverse forward unrealized mark-to-market (gains) losses	$	15.5	$	141.1		$	11.1	$	(102.1	)

Add realized mark-to-market gains previously recognized	$	80.0	$	71.9		$	256.9	$	262.2


Recurring segment profit after mark-to-market adjustments	$	492.4	$	382.0		$	1,429.8	$	1,130.4

Williams’ businesses reported consolidated segment profit of $395.8 million in the third-quarter this year, 94 percent higher than $204.5 million a year ago.

These significantly higher results in third-quarter 2006 are primarily attributable to higher margins for NGL sales, significantly lower levels of forward unrealized mark-to-market losses and increased natural gas production. These benefits were partially offset by higher operating and maintenance costs.

For the first three quarters of 2006, Williams’ businesses reported consolidated segment profit of $1.1 billion, an increase of 13 percent compared with $970.6 million for the same period in 2005.

Results for the first nine months of 2005 benefited from $102.1 million of forward unrealized mark-to-market gains in Power, compared with a forward unrealized loss of $11.1 million for the same period in 2006. The 2006 period also includes approximately $70 million in litigation accruals associated with the Gulf Liquids verdict earlier this year.

On a basis adjusted to remove the effect of nonrecurring items and mark-to-market accounting, Williams had recurring consolidated segment profit of $492.4 million in third-quarter 2006, compared with $382.0 million a year ago – an increase of 29 percent. On the same basis, Williams had recurring consolidated segment profit of approximately $1.4 billion in the first three quarters of 2006, compared with approximately $1.1 billion for the same period in 2005 – an increase of 26 percent.

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

For the first three quarters of 2006, net cash provided by operating activities was approximately $1.3 billion, compared with approximately $1.1 billion for the same period in 2005. Net cash generated this year is primarily being reinvested in capital expenditures.

Williams invested approximately $1.8 billion in capital expenditures in the first nine months this year, essentially doubling investments of approximately $886 million in the same period a year ago.

Williams — 3rd Quarter Results — Nov. 2, 2006 — Page 4 of 11

Exploration & Production: Volumes Up 22% From Year Ago

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 third-quarter 2006 segment profit of $144.5 million, compared with segment profit of $158.8 million a year ago. The third quarter of 2005 included the benefit of a $21.7 million gain on the sale of certain properties in the Powder River Basin.

Average daily production from domestic and international interests in third-quarter 2006 totaled 831 MMcfe, an increase of 22 percent compared with volumes of 682 MMcfe in third-quarter 2005.

Third-quarter 2006 average daily production in the Piceance Basin was 430 MMcfe – up 31 percent compared with 329 MMcfe in third-quarter 2005.

Production in the Powder River Basin also increased – up 23 percent to 147 MMcfe, compared with 120 MMcfe a year ago. Increased production in the Powder River primarily is coming from volumes in the Big George area of the basin.

The benefit of higher production volumes in the third quarter of 2006 was partially offset by 10 percent lower domestic net realized average prices; increased lease operating expenses; higher depreciation, depletion and amortization; and higher general and administrative expenses due to increased business activities and generally higher industry costs. However, third-quarter 2006 included a $5 million unrealized gain from hedge ineffectiveness and certain basis swaps not designated as hedges, compared with a $16 million unrealized loss for third-quarter 2005.

For the first nine months of 2006, Exploration & Production reported segment profit of $411.9 million, an increase of 8 percent compared with $380.8 million for the first three quarters of 2005.

The improvement in the first three quarters of 2006 primarily reflects increased production volumes. The first nine months of 2006 also include a $21 million unrealized gain from hedge ineffectiveness and certain basis swaps not designated as hedges, compared with a $16 million unrealized loss for the same period in 2005.

Year-to-date increases in 2006 were partially offset by the same expense items previously noted for the third quarter, as well as the absence of gains totaling $29.6 million on the sale of certain assets in 2005.

Williams now has 24 rigs operating in the Piceance Basin of western Colorado – 9 more than it had at this time a year ago. The rig count includes eight new-generation drilling rigs that are purpose-built for conditions in the tight-sands development. Two more of the new rigs are scheduled for delivery later this year.

Williams is on pace to invest $1.15 billion to $1.25 billion in Exploration & Production in 2006. These investments primarily focus on increasing the pace of developing the company’s natural gas reserves.

Williams has narrowed the range of segment profit it expects from Exploration & Production in 2006 based on lower domestic net realized prices and higher lease operating expenses in the third quarter. The company now expects $550 million to $600 million in segment profit for this business. The company’s prior guidance was $550 million to $650 million.

Williams — 3rd Quarter Results — Nov. 2, 2006 — Page 5 of 11

Midstream Gas & Liquids: 3Q Segment Profit Rises 75 Percent

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

This business reported segment profit of $212.2 million in the third quarter, up 75 percent compared with $121.1 million a year ago.

The significant increase in Midstream’s results is primarily from higher margins realized from the company’s NGL sales. Per-unit margins in third-quarter 2006 were approximately 112 percent higher than margins in the same period a year ago. Williams markets natural gas liquids via equity volumes the company retains as payment-in-kind under certain processing contracts.

In addition, Williams experienced strong growth in production handling volumes and revenues in the deepwater Gulf of Mexico, and higher fee-based gathering and processing revenues. The 2006 quarter also benefited from $7.9 million in gains on asset sales. These benefits were partially offset by higher operating expenses, a $10.6 million adjustment to increase accrued accounts payable and a $5.2 million loss associated with an asset abandonment.

In third-quarter 2006, Midstream sold 334.0 million gallons of NGL equity volumes – 21 percent higher than equity sales of 276.4 million gallons in third-quarter 2005.

For the first nine months of 2006, Midstream reported segment profit of $494.4 million, 38 percent higher than $358.8 million for the first three quarters of 2005.

The improvement in 2006 primarily reflects a $164.2 million increase in NGL 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 by higher operating expenses and approximately $70 million in litigation accruals associated with the Gulf Liquids matter.

Year-to-date through Sept. 30, the sale of Williams’ NGL equity volumes has generated margins of $323.4 million, 103 percent higher than margins of $159.2 million for the same period in 2005. Higher margins during the first three quarters of 2006 are primarily the result of the difference between higher liquids prices – which typically track closely with crude oil prices – and lower natural gas prices.

The Cameron Meadows natural gas processing plant in Louisiana’s Cameron Parish is returning to its full design capacity after being damaged by Hurricane Rita in September 2005. The plant is expected to be available to process up to 500 MMcf/d of natural gas in early November as crews finalize the startup procedures on the plant’s second processing unit. Cameron Meadows had been operating at about half of its design capacity since February.

Williams — 3rd Quarter Results — Nov. 2, 2006 — Page 6 of 11

Williams is raising its guidance again for segment profit it expects from Midstream. The company now expects $675 million to $750 million in segment profit for this business in 2006 based on its performance in the first three quarters and Williams’ outlook for strong NGL prices. The company’s prior guidance in August was $550 million to $675 million in segment profit for Midstream.

Gas Pipeline: Capacity Replacement Project Nearing Completion

Gas Pipeline primarily delivers natural gas to markets along the Eastern Seaboard, in the Northwest, and in Florida. This business reported third-quarter 2006 segment profit of $109.0 million, down 32 percent compared with $161.1 million a year ago.

Results for the third quarter of 2006 were reduced by approximately $22 million in higher selling, general and administrative costs primarily due to higher personnel costs, property insurance costs and information systems support costs. In addition, the results reflect approximately $8 million in lower equity earnings and higher operating and maintenance costs related to pipeline assessment and repair costs.

The third-quarter of 2005 benefited from a $14 million favorable adjustment from the resolution of litigation associated with Gas Pipeline’s fuel tracker filings.

New rates for both of Williams’ wholly-owned interstate transmission systems – Transco and Northwest Pipeline – will be effective, subject to refund, in first-quarter 2007. Northwest Pipeline filed its rate case with the Federal Energy Regulatory Commission on June 30. Transco filed its rate case Aug. 31. The filings reflect, among other things, current levels of operating costs and rate base.

For the first nine months of 2006, Gas Pipeline reported segment profit of $366.4 million, down 26 percent compared with $493.0 million for the same period in 2005.

The reduction for the first three quarters of 2006 is attributable to higher operating and maintenance costs; higher selling, general and administrative costs, including the absence of a $34.8 million benefit in prior-period adjustments recorded in 2005; and the absence of the $14 million benefit of the 2005 fuel tracker settlement. The increased costs are primarily due to the same factors previously mentioned for the third quarter.

In July, Transco filed an application with the Federal Energy Regulatory Commission to provide additional capacity to the greater Washington D.C. and Baltimore metropolitan areas. The proposal, known as the Potomac Expansion, is designed to increase firm transportation capacity by 165,000 dekatherms per day beginning in November 2007.

In August, the commission also issued a certificate enabling Northwest Pipeline to proceed with a 37-mile expansion in Colorado known as the Parachute Lateral project. The 450,000-dekatherm expansion is scheduled to be completed by January 2007.

Williams — 3rd Quarter Results — Nov. 2, 2006 — Page 7 of 11

Northwest Pipeline expects to have its Capacity Replacement project between Sumas, Wash., and Washougal, Wash., in service by December. The company abandoned 268-miles of 26-inch diameter pipeline and replaced its 360,000 dekatherms of capacity with 80-miles of 36-inch diameter pipeline in four sections along the same corridor. Startup operations on the new pipeline sections began the week of Oct. 23.

Williams has narrowed the range of segment profit it expects from Gas Pipeline. The company now expects $475 million to $500 million in segment profit for this business in 2006. Williams previously expected $475 million to $520 million in segment profit for Gas Pipeline.

Power: Solid Performance as Expected

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



Power Recurring Segment Profit (Loss) Adjusted for Mark-to-Market Effect	3Q						YTD
Amounts are reported in millions	2006			2005			2006			2005
Segment loss	$	(69.7	)	$	(226.4	)	$	(171.8	)	$	(187.3	)
Nonrecurring adjustments	$	(9.2	)	$	0.4		$	(9.2	)	$	24.9

Recurring segment loss	$	(78.9	)	$	(226.0	)	$	(181.0	)	$	(162.4	)
Mark-to-market adjustments — net	$	95.5		$	213.0		$	268.0		$	160.1

Recurring segment profit (loss) after MTM adjustments	$	16.6		$	(13.0	)	$	87.0		$	(2.3	)

Power reported a third-quarter 2006 segment loss of $69.7 million, compared with a segment loss of $226.4 million for third-quarter 2005. Results include the effect of forward noncash unrealized mark-to-market gains and losses.

The improved results in third-quarter 2006 are primarily the result of lower noncash unrealized mark-to-market losses, higher accrual portfolio earnings and the benefit of a $12.7 million reduction in contingent obligations associated with a former business. The improvement was partially offset by a $3.5 million litigation accrual.

On a basis adjusted for the effect of mark-to-market accounting, Power reported recurring segment profit of $16.6 million in third-quarter 2006, compared with a recurring segment loss of $13.0 million in the 2005 period.

The improvement in third-quarter 2006 recurring segment profit adjusted to remove the effect of mark-to-accounting reflects the benefit of having additional megawatts economically hedged on Power’s tolling positions. Third-quarter 2006 adjusted results include approximately $13 million of losses related to the write-down of natural gas storage inventory due to falling prices and $7 million of certain related realized hedge losses.

Williams — 3rd Quarter Results — Nov. 2, 2006 — Page 8 of 11

These losses – on a basis adjusted for mark-to-market accounting – are timing-related only. The company expects to recover these losses since the inventory is hedged at fixed prices.

For the first nine months of 2006, Power reported a segment loss of $171.8 million, compared with a segment loss of $187.3 million for the first three quarters of 2005. The improved results in 2006 are primarily the result of higher accrual portfolio earnings and a $24.8 million gain on the sale of certain third party receivables in first-quarter 2006, offset by lower noncash unrealized mark-to-market earnings.

The 2006 period includes forward unrealized mark-to-market losses of $11.1 million, compared with forward unrealized mark-to-market gains of $102.1 million in the first nine months of 2005. The year-over-year variance resulted primarily from commodity price changes on fewer nondesignated contracts subject to mark-to-market accounting.

For the first nine months of 2006, Power reported a recurring segment profit on a basis to remove the effect of mark-to-market accounting of $87.0 million, significantly improved compared with a loss $2.3 million for the first three quarters of 2005.

The year-to-date improvement primarily reflects the benefits of having additional megawatts economically hedged on Power’s tolling positions, the liquidation of certain non-core basis positions in the gas portfolio and lower expenses from the positive effect of a gain on the sale of certain third-party receivables in the first quarter.

The 2006 adjusted results also include $20 million of storage-related losses for the write-down of natural gas inventory due to falling prices and $30 million of certain related realized hedge losses. These losses – on a basis adjusted for mark-to-market accounting – are timing-related only. The company expects to recover these losses since the inventory is hedged at fixed prices.

For 2006, Williams now expects a segment loss of $190 million to $240 million from Power, which includes year-to-date unrealized mark-to-market losses on derivative contracts but assumes no future change in fair value on these contracts. Williams previously expected a segment loss of $150 million to $200 million from Power.

Williams continues to expect Power to generate 2006 recurring segment profit of $75 million to $125 million after removing the effect of mark-to-market accounting.

Today’s Analyst Call

Williams’ management will discuss the company’s third-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.

Williams — 3rd Quarter Results — Nov. 2, 2006 — Page 9 of 11

A limited number of phone lines also will be available at (800) 500-0311. International callers should dial (719) 457-2698. Callers should dial in at least 10 minutes prior to the start of the discussion. Replays of the third-quarter webcast will be available for two weeks at www.williams.com.

Form 10-Q

The company is filing its Form 10-Q today 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:		Julie Gentz
		Williams (media relations)
		(918) 573-3053

		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 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

Williams — 3rd Quarter Results — Nov. 2, 2006 — Page 10 of 11

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 than 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 — 3rd Quarter Results — Nov. 2, 2006 — Page 11 of 11

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			3rd 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	)	$	110.1		$	177.3


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	)	$	0.19		$	0.29


Nonrecurring items:

Exploration & Production
Gains on sales 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
Gains on sales of MGL properties		—			—			—			—			—			—			—			(7.9	)		(7.9	)
Adjustment of accounts payable accrual		—			—			—			—			—			—			—			10.6			10.6
Losses on asset retirements and abandonments		—			—			—			—			—			—			—			5.2			5.2
Accrual for Gulf Liquids litigation contingency		—			—			—			—			—			—			68.0			2.4			70.4
Settlement of an international contract dispute		—			—			—			—			—			(6.3	)		—			—			(6.3	)

Total Midstream Gas & Liquids nonrecurring items		—			—			—			—			—			(6.3	)		68.0			10.3			72.0

Power
Reduction of contingent obligations associated with our former distributive power generation business		—			—			—			—			—			—			—			(12.7	)		(12.7	)
Accrual for a regulatory settlement ⁽¹⁾		4.6			—			—			—			4.6			—			—			—			—
Accrual for litigation contingencies ⁽¹⁾		—			13.1			0.4			68.7			82.2			—			—			3.5			3.5
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			—			—			(9.2	)		(9.2	)

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			1.1			60.8

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			3.4			165.3
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)		—			—			—			—			—			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			0.6			20.6

		2.7			(8.6	)		18.8			9.4			22.3			16.5			185.1			4.0			205.6

Total nonrecurring items		(6.6	)		35.9			(16.7	)		167.5			180.1			8.2			253.1			5.1			266.4
Tax effect for above items ⁽¹⁾		(2.8	)		10.7			(6.4	)		48.0			49.5			3.4			76.6			1.8			81.8
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		$	113.4		$	361.9


Recurring diluted earnings (loss) per common share	$	0.33		$	0.11			($0.01	)	$	0.28		$	0.72		$	0.23		$	0.19		$	0.19		$	0.60


Weighted-average shares — diluted (thousands)		599,422			578,902			580,735			609,106			605,847			607,073			595,561			609,062			608,045


⁽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			3rd Qtr			Year

Revenues	$	2,954.0		$	2,871.2		$	3,082.3		$	3,676.1		$	12,583.6		$	3,027.5		$	2,715.1		$	3,300.0		$	9,042.6

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			2,822.4			7,684.9
Selling, general and administrative expenses		73.5			62.7			90.6			98.6			325.4			71.0			109.3			128.0			308.3
Other (income) expense — net		(1.8	)		21.9			(21.4	)		62.5			61.2			(22.3	)		61.7			(15.8	)		23.6

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			2,934.6			8,016.8


Equity earnings		17.7			9.8			17.6			20.5			65.6			22.2			23.1			29.9			75.2
Income (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			395.8			1,101.0


Reclass equity earnings		(17.7	)		(9.8	)		(17.6	)		(20.5	)		(65.6	)		(22.2	)		(23.1	)		(29.9	)		(75.2	)
Reclass income (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	)		(35.0	)		(99.3	)
Securities litigation settlement and related fees		—			—			—			—			—			(1.2	)		(160.7	)		(3.4	)		(165.3	)


Operating income		464.0			259.5			144.1			303.5			1,171.1			358.3			75.9			327.0			761.2

Interest accrued		(164.7	)		(164.6	)		(166.0	)		(176.4	)		(671.7	)		(162.8	)		(181.5	)		(162.7	)		(507.0	)
Interest capitalized		1.1			1.4			1.8			2.9			7.2			3.0			4.0			4.8			11.8
Investing income (loss)		31.0			(17.2	)		31.1			(21.2	)		23.7			46.9			43.3			50.7			140.9
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	)		(12.1	)		(27.5	)
Other income (expense) — net		5.5			8.1			(1.1	)		14.6			27.1			8.1			8.0			2.8			18.9


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	)		210.5			366.9
Provision (benefit) for income taxes		129.5			41.7			(2.6	)		45.3			213.9			88.3			0.9			100.4			189.6


Income (loss) from continuing operations		202.2			40.7			5.7			68.8			317.4			131.1			(63.9	)		110.1			177.3

Income (loss) from discontinued operations		(1.1	)		0.6			(1.3	)		(0.3	)		(2.1	)		0.8			(12.1	)		(3.9	)		(15.2	)


Income (loss) before cumulative effect of change in accounting principle		201.1			41.3			4.4			68.5			315.3			131.9			(76.0	)		106.2			162.1
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	)	$	106.2		$	162.1


Diluted earnings per common share:
Income (loss) from continuing operations	$	0.34		$	0.07		$	0.01		$	0.11		$	0.53		$	0.22		$	(0.11	)	$	0.19		$	0.29
Loss from discontinued operations		—			—			—			—			—			—			(0.02	)		(0.01	)		(0.02	)

Net income (loss)	$	0.34		$	0.07		$	0.01		$	0.11		$	0.53		$	0.22		$	(0.13	)	$	0.18		$	0.27


Weighted-average number of shares used in computation (thousands)		599,422			578,902			580,735			609,106			605,847			607,073			595,561			609,062			608,045

Common shares outstanding at end of period (thousands)		570,501			571,502			572,922			573,592			573,592			595,007			595,562			596,130			596,130

Market price per common share (end of period)	$	18.81		$	19.00		$	25.05		$	23.17		$	23.17		$	21.39		$	23.36		$	23.87		$	23.87

Common dividends per share	$	0.05		$	0.05		$	0.075		$	0.075		$	0.25		$	0.075		$	0.09		$	0.09		$	0.255


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			3rd Qtr			Year

Segment profit (loss):

Exploration & Production	$	103.7		$	118.3		$	158.8		$	206.4		$	587.2		$	147.6		$	119.8		$	144.5		$	411.9
Gas Pipeline		167.4			164.5			161.1			92.8			585.8			134.7			122.7			109.0			366.4
Midstream Gas & Liquids		128.6			109.1			121.1			112.4			471.2			151.5			130.7			212.2			494.4
Power		114.1			(75.0	)		(226.4	)		(69.4	)		(256.7	)		(22.5	)		(79.6	)		(69.7	)		(171.8	)
Other		(4.1	)		(60.5	)		(10.1	)		(30.3	)		(105.0	)		1.0			(0.7	)		(0.2	)		0.1

Total segment profit	$	509.7		$	256.4		$	204.5		$	311.9		$	1,282.5		$	412.3		$	292.9		$	395.8		$	1,101.0


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			10.3			72.0
Power		11.4			13.1			0.4			91.7			116.6			—			—			(9.2	)		(9.2	)
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		$	1.1		$	60.8


Recurring segment profit (loss):

Exploration & Production		96.1			118.3			137.1			206.4			557.9			147.6			119.8			144.5			411.9
Gas Pipeline		154.3			142.8			146.9			130.1			574.1			132.7			122.7			109.0			364.4
Midstream Gas & Liquids		128.6			109.1			121.1			112.4			471.2			145.2			198.7			222.5			566.4
Power		125.5			(61.9	)		(226.0	)		22.3			(140.1	)		(22.5	)		(79.6	)		(78.9	)		(181.0	)
Other		(4.1	)		(7.4	)		(10.1	)		(1.2	)		(22.8	)		1.0			(0.7	)		(0.2	)		0.1

Total recurring segment profit	$	500.4		$	300.9		$	169.0		$	470.0		$	1,440.3		$	404.0		$	360.9		$	396.9		$	1,161.8


Note:		Segment profit (loss) includes equity earnings (loss) and certain income (loss) from investments reported in Investing income (loss) 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.

Exploration & Production
(UNAUDITED)


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

Revenues:
Production	$	210.2		$	234.8		$	283.0		$	344.4		$	1,072.4		$	286.8		$	287.9		$	316.1		$	890.8
Gas management		28.2			32.6			32.1			52.0			144.9			41.2			28.3			25.3			94.8
Net nonqualified hedge derivative income (loss)		(0.1	)		0.6			(15.9	)		9.8			(5.6	)		12.8			(1.6	)		1.8			13.0
International		10.8			11.6			16.3			14.7			53.4			16.0			15.1			16.8			47.9
Other		(0.1	)		1.9			2.9			(0.7	)		4.0			(0.8	)		12.6			11.1			22.9

Total revenues		249.0			281.5			318.4			420.2			1,269.1			356.0			342.3			371.1			1,069.4

Segment costs and expenses:
Depreciation, depletion and amortization (including International)		58.5			59.5			66.4			69.6			254.0			73.1			84.5			95.3			252.9
Lease and other operating expenses *		23.8			23.9			28.5			29.0			105.2			30.1			43.8			39.0			112.9
Operating taxes		21.1			23.9			26.7			29.4			101.1			31.8			28.1			31.1			91.0
Exploration expenses *		0.9			1.1			1.5			4.1			7.6			4.4			2.4			2.6			9.4
Gathering expense		5.6			6.0			5.0			8.1			24.7			6.4			7.5			7.6			21.5
Selling, general and administrative expenses (including International)		17.0			17.7			20.3			24.6			79.6			21.5			28.2			28.2			77.9
Gas management expenses		28.2			32.6			32.1			52.0			144.9			41.2			28.3			25.3			94.8
International (excluding DD&A and SG&A)		3.3			3.3			4.7			3.6			14.9			5.5			4.9			5.0			15.4
Other (income) expense — net		(9.6	)		(1.2	)		(19.8	)		(0.7	)		(31.3	)		(0.6	)		0.7			(1.9	)		(1.8	)

Total segment costs and expenses		148.8			166.8			165.4			219.7			700.7			213.4			228.4			232.2			674.0

Equity earnings — International		3.5			3.6			5.8			5.9			18.8			5.0			5.9			5.6			16.5


Reported segment profit		103.7			118.3			158.8			206.4			587.2			147.6			119.8			144.5			411.9

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		$	144.5		$	411.9


* 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			71.8			198.4
Net domestic volumes per day (MMcfe/d)		568			604			629			646			612			661			738			780			727
Net domestic realized price ($/Mcfe) (1)	$	4.001		$	4.164		$	4.801		$	5.655		$	4.688		$	4.712		$	4.177		$	4.300		$	4.382
Production taxes per Mcfe	$	0.413		$	0.435		$	0.462		$	0.493		$	0.452		$	0.534		$	0.420		$	0.433		$	0.459
Lease and other operating expense per Mcfe	$	0.466		$	0.436		$	0.492		$	0.486		$	0.471		$	0.505		$	0.653		$	0.544		$	0.569

(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			6.0			17.6
Volumes per day (MMcfe/d)		59			61			67			65			63			67			61			65			64

Volumes net to Williams (after minority interest) (Bcfe)		4.1			4.3			4.8			4.8			18.0			4.7			4.4			4.7			13.8
Volumes net to Williams per day (MMcfe/d)		46			48			53			51			49			53			48			51			51

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			76.5			212.2
Volumes net to Williams per day (MMcfe/d)		614			652			682			697			662			714			786			831			777

Gas Pipeline
(UNAUDITED)


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

Revenues:
Northwest Pipeline	$	80.3		$	78.9		$	79.6		$	82.7	$	321.5		$	79.6		$	80.0		$	81.0		$	240.6
Transcontinental Gas Pipe Line		254.9			278.1			266.0			292.0		1,091.0			254.3			257.2			253.0			764.5
Other		0.1			—			0.2			—		0.3			0.1			0.1			0.2			0.4

Total revenues		335.3			357.0			345.8			374.7		1,412.8			334.0			337.3			334.2			1,005.5

Segment costs and expenses:
Costs and operating expenses		160.4			193.3			177.6			250.7		782.0			177.2			192.8			192.2			562.2
Selling, general and administrative expenses		18.6			6.8			23.6			35.1		84.1			31.0			35.4			45.1			111.5
Other (income) expense — net		0.3			0.3			0.5			3.4		4.5			(1.4	)		(3.4	)		(2.4	)		(7.2	)

Total segment costs and expenses		179.3			200.4			201.7			289.2		870.6			206.8			224.8			234.9			666.5

Equity earnings		11.4			7.9			17.0			7.3		43.6			7.5			10.7			9.2			27.4
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			31.8			97.9
Transcontinental Gas Pipe Line		117.9			121.8			107.0			50.1		396.8			95.8			81.3			69.5			246.6
Other		9.8			6.2			15.0			5.5		36.5			5.6			8.6			7.7			21.9

Total reported segment profit		167.4			164.5			161.1			92.8		585.8			134.7			122.7			109.0			366.4

Nonrecurring adjustments:
Northwest Pipeline		—			—			—			—		—			—			—			—			—
Transcontinental Gas Pipe Line		(13.1	)		(21.7	)		(14.2	)		37.3		(11.7	)		(2.0	)		—			—			(2.0	)
Other		—			—			—			—		—			—			—			—			—
											^a^a^a^a^a ^a
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			31.8			97.9
Transcontinental Gas Pipe Line		104.8			100.1			92.8			87.4		385.1			93.8			81.3			69.5			244.6
Other		9.8			6.2			15.0			5.5		36.5			5.6			8.6			7.7			21.9

Total recurring segment profit, pre-tax	$	154.3		$	142.8		$	146.9		$	130.1	$	574.1		$	132.7		$	122.7		$	109.0		$	364.4


Operating statistics

Northwest Pipeline
Throughput (TBtu)		181.2			146.2			152.9			192.6		672.9			179.7			142.7			156.6			479.0
Average daily transportation volumes (TBtu)		2.0			1.6			1.7			2.1		1.9			2.0			1.6			1.7			1.8
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)		537.7			427.9			453.6			466.6		1,885.8			502.8			427.0			471.3			1,401.1
Average daily transportation volumes (TBtu)		6.0			4.7			4.9			5.1		5.2			5.6			4.6			5.1			5.1
Average daily firm reserved capacity (TBtu)		6.9			6.5			6.4			6.8		6.7			7.0			6.4			6.4			6.6

Midstream Gas & Liquids
(UNAUDITED)


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

Revenues:
Gathering	$	70.6		$	74.2		$	74.0		$	75.8		$	294.6		$	76.8		$	79.0		$	79.2		$	235.0
Processing		23.5			24.3			25.5			22.9			96.2			24.9			27.4			27.6			79.9
Venezuela fee revenue		36.5			37.8			40.4			38.8			153.5			38.9			38.0			40.6			117.5
NGL sales from gas processing		285.1			247.0			244.2			259.0			1,035.3			263.7			292.6			296.6			852.9
Production handling and transportation		18.6			20.4			14.7			20.6			74.3			37.2			33.2			33.0			103.4
Olefins sales (Incl Gulf and Canada)		146.6			114.2			121.4			185.3			567.5			148.9			131.4			175.9			456.2
Trading/marketing sales		588.0			574.4			522.0			578.1			2,262.5			709.0			806.1			863.9			2,379.0
Other revenues		23.7			33.2			31.7			39.1			127.7			34.4			30.7			28.8			93.9

		1,192.6			1,125.5			1,073.9			1,219.6			4,611.6			1,333.8			1,438.4			1,545.6			4,317.8
Intrasegment eliminations		(385.6	)		(345.4	)		(319.2	)		(328.7	)		(1,378.9	)		(354.4	)		(394.9	)		(428.6	)		(1,177.9	)

Total revenues		807.0			780.1			754.7			890.9			3,232.7			979.4			1,043.5			1,117.0			3,139.9
Segment costs and expenses:
NGL cost of goods sold		225.1			202.4			189.6			218.3			835.4			199.9			172.7			156.9			529.5
Olefins cost of goods sold		118.7			104.0			102.2			163.5			488.4			132.8			108.1			141.2			382.1
Trading/marketing cost of goods sold		584.0			574.7			510.1			575.8			2,244.6			716.7			799.1			863.4			2,379.2
Venezuela operating costs		16.1			16.0			17.4			17.6			67.1			16.8			18.1			17.1			52.0
Operating costs		101.6			101.5			112.8			113.9			429.8			120.6			120.7			134.2			375.5
Other
Selling, general and administrative expenses		22.9			21.0			23.1			29.3			96.3			23.3			25.2			31.1			79.6
Other (income) expense — net		2.6			1.7			0.8			(1.7	)		3.4			(17.9	)		70.0			(3.2	)		48.9
Intrasegment eliminations		(385.5	)		(345.5	)		(319.2	)		(328.7	)		(1,378.9	)		(354.4	)		(394.9	)		(428.6	)		(1,177.9	)

Total segment costs and expenses		685.5			675.8			636.8			788.0			2,786.1			837.8			919.0			912.1			2,668.9
Equity earnings		7.1			4.1			3.2			9.2			23.6			9.9			6.2			7.3			23.4
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			212.2			494.4
Nonrecurring adjustments		—			—			—			—			—			(6.3	)		68.0			10.3			72.0

Recurring segment profit, pre-tax	$	128.6		$	109.1		$	121.1		$	112.4		$	471.2		$	145.2		$	198.7		$	222.5		$	566.4


Operating statistics

Gathering volumes (TBtu)		315.5			323.6			310.3			303.9			1,253.3			296.9			300.1			292.5			889.5
Gathering margins ($/MMBtu)	$	0.2237		$	0.2292		$	0.2386		$	0.2496		$	0.2351		$	0.2590		$	0.2634		$	0.2708		$	0.2642

Processing volumes (TBtu)		181.0			184.5			190.3			165.6			721.4			191.8			204.8			210.0			606.6
Processing rate ($/MMBtu)	$	0.1299		$	0.1316		$	0.1342		$	0.1381		$	0.1334		$	0.1298		$	0.1340		$	0.1314		$	0.1317

NGL equity sales (million gallons)		398.7			338.3			276.4			255.8			1,269.2			333.7			361.3			334.0			1,029.0
NGL margin ($/gallon)	$	0.1503		$	0.1318		$	0.1976		$	0.1565		$	0.1569		$	0.1900		$	0.3319		$	0.4183		$	0.3143

Olefins sales (Ethylene & Propylene) (million lbs)		266.5			265.6			258.1			275.9			1,066.1			259.2			196.8			268.1			724.1

Power
(UNAUDITED)


	2005															2006
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd 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		$	2,104.1		$	5,764.0
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			2,104.1		$	5,764.3

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			2,167.6			5,921.1
Selling, general and administrative expenses		16.0			16.9			21.1			10.5			64.5			(4.5	)		18.9			22.2			36.6
Other (income) expense — net		5.6			17.3			(1.7	)		95.5			116.7			(2.1	)		(3.4	)		(8.4	)		(13.9	)

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			2,181.4			5,943.8

Equity Earnings		1.1			0.9			1.0			0.1			3.1			(0.2	)		0.3			7.6			7.7


Reported segment profit (loss)		114.1			(75.0	)		(226.4	)		(69.4	)		(256.7	)		(22.5	)		(79.6	)		(69.7	)		(171.8	)

Nonrecurring adjustments		11.4			13.1			0.4			91.7			116.6			—			—			(9.2	)		(9.2	)


Recurring segment profit (loss), pre-tax	$	125.5		$	(61.9	)	$	(226.0	)	$	22.3		$	(140.1	)	$	(22.5	)	$	(79.6	)	$	(78.9	)	$	(181.0	)

Operating statistics

Volumes
Natural gas (Bcfd)
Sales to third parties		1.7			1.8			1.7			1.7			1.7			1.7			1.5			1.7			1.6
Sales to other segments		0.6			0.4			0.3			0.3			0.4			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			0.4			0.2

Total managed		2.5			2.4			2.3			2.1			2.3			2.2			2.1			2.5			2.2
Crude & refined products (MBPD)		—			—			—			—			—			—			—			—			—
Power (GWh)		14,832			15,906			21,690			14,559			66,987			11,505			12,949			17,430			41,884

Additional statistics

Value at risk


	Quarter ended 9/30/2006
	(in Millions)
One day VaR - 95% confidence level
Trading	$	1.8MM
Non-Trading	$	16.3MM
Aggregate Earnings VaR	$	5.2MM


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


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

Net Credit Exposure


(in Millions)	Investment
	Grade		Total
Gas and electric utilities	$	177.7	$	177.9
Energy marketers and traders		279.1		589.1
Financial institutions		198.9		198.9
Other		23.8		23.8

	$	679.5	$	989.7

Credit Reserves				(25.1	)

Net Credit Exposure from Derivative Contracts			$	964.6

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	$	25.0
13-36 months		0.7
37-60 months		(0.7	)
61-120 months		(0.4	)
121+ months		0.1

Total Fair Value		24.7

Non-Trading MTM Derivatives and SFAS 133 Hedges		378.6
Non-Power Business Unit Hedges		23.7

Total Net Derivative Assets and Liabilities	$	427.0


Power Portfolio	Quarter Ended
(Megawatts)	9/30/06		9/30/05
Owned		207		207
Contracted		8,114		9,012

Total		8,321		9,219

Credit Support (in Millions)


As of September 30, 2006
Prepays	$	5

Margins	$	0

Adequate Assurance	$	9

Capital Expenditures and Investments
(UNAUDITED)


	2005											2006
(Dollars in millions)	1st Qtr			2nd Qtr		3rd Qtr		4th Qtr		Year		1st Qtr			2nd Qtr		3rd Qtr			Year
Capital expenditures:
Exploration & Production	$	158.6		$	182.8	$	211.1	$	230.8	$	783.3	$	310.3		$	283.9	$	384.9		$	979.1

Gas Pipeline:
Northwest Pipeline		12.0			29.6		43.2		52.2		137.0		40.3			96.0		177.4			313.7
Transcontinental Gas Pipe Line		35.7			55.0		80.7		83.1		254.5		46.4			106.7		109.4			262.5
Other		—			—		—		2.2		2.2		—			—		—			—

Total		47.7			84.6		123.9		137.5		393.7		86.7			202.7		286.8			576.2

Midstream Gas & Liquids		16.3			25.5		32.7		40.7		115.2		70.7			39.3		83.5			193.5
Power		1.0			0.7		0.4		0.1		2.2		0.6			0.6		(0.1	)		1.1
Other		(0.7	)*		0.1		1.2		4.0		4.6		—			7.8		1.2			9.0

Total	$	222.9		$	293.7	$	369.3	$	413.1	$	1,299.0	$	468.3		$	534.3	$	756.3		$	1,758.9


Purchase of investments:
Exploration & Production	$	6.3		$	—	$	0.3	$	—	$	6.6	$	—		$	—	$	—		$	—
Gas Pipeline		—			—		—		—		—		—			—		4.5			4.5
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		4.6			43.7

Total	$	26.3		$	55.6	$	16.3	$	17.9	$	116.1	$	9.7		$	26.8	$	9.1		$	45.6


Summary:
Exploration & Production	$	164.9		$	182.8	$	211.4	$	230.8	$	789.9	$	310.3		$	283.9	$	384.9		$	979.1
Gas Pipeline		47.7			84.6		123.9		137.5		393.7		86.7			202.7		291.3			580.7
Midstream Gas & Liquids		16.3			60.5		44.2		40.7		161.7		67.3			40.1		83.5			190.9
Power		1.0			0.7		0.4		0.1		2.2		0.6			0.6		(0.1	)		1.1
Other		19.3			20.7		5.7		21.9		67.6		13.1			33.8		5.8			52.7

Total	$	249.2		$	349.3	$	385.6	$	431.0	$	1,415.1	$	478.0		$	561.1	$	765.4		$	1,804.5


Cumulative summary:
Exploration & Production	$	164.9		$	347.7	$	559.1	$	789.9	$	789.9	$	310.3		$	594.2	$	979.1		$	979.1
Gas Pipeline		47.7			132.3		256.2		393.7		393.7		86.7			289.4		580.7			580.7
Midstream Gas & Liquids		16.3			76.8		121.0		161.7		161.7		67.3			107.4		190.9			190.9
Power		1.0			1.7		2.1		2.2		2.2		0.6			1.2		1.1			1.1
Other		19.3			40.0		45.7		67.6		67.6		13.1			46.9		52.7			52.7

Total	$	249.2		$	598.5	$	984.1	$	1,415.1	$	1,415.1	$	478.0		$	1,039.1	$	1,804.5		$	1,804.5


*		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			3rd Qtr			Year

Depreciation, depletion and amortization:
Exploration & Production	$	58.6		$	59.4		$	66.4		$	69.8		$	254.2		$	73.0			84.2			94.8			252.0
Gas Pipeline:
Northwest Pipeline		17.3			17.0			17.9			18.4			70.6			18.5			18.8			19.1			56.4
Transcontinental Gas Pipe Line		49.4			48.6			49.3			49.4			196.7			50.0			51.7			51.2			152.9

Total		66.7			65.6			67.2			67.8			267.3			68.5			70.5			70.3			209.3
Midstream Gas & Liquids		46.0			46.4			49.5			50.1			192.0			49.4			49.9			49.9			149.2
Power		3.9			3.7			3.6			3.7			14.9			3.2			3.2			2.3			8.7
Other		3.0			3.0			2.9			2.7			11.6			2.9			2.7			3.1			8.7

Total	$	178.2		$	178.1		$	189.6		$	194.1		$	740.0		$	197.0		$	210.5		$	220.4		$	627.9


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		$	1,074.6		$	1,074.6

Total assets	$	26,434.1		$	26,399.7		$	33,655.8		$	29,442.6		$	29,442.6		$	26,029.0		$	25,617.2		$	24,821.5		$	24,821.5

Capital structure:
Debt
Current	$	99.5		$	98.6		$	122.4		$	122.6		$	122.6		$	175.7		$	170.7		$	142.3		$	142.3
Noncurrent	$	7,650.4		$	7,645.7		$	7,598.7		$	7,590.5		$	7,590.5		$	7,252.8		$	7,292.6		$	7,275.2		$	7,275.2
Stockholders’ equity	$	5,261.1		$	5,353.6		$	5,154.4		$	5,427.5		$	5,427.5		$	5,925.5		$	5,882.3		$	6,071.2		$	6,071.2
Debt to debt-plus-equity ratio		59.6	%		59.1	%		60.0	%		58.7	%		58.7	%		55.6	%		55.9	%		55.0	%		55.0	%

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	$	113		$	362	$	198		$	66		$	(5	)	$	168		$	428
Recurring diluted earnings per common share	$	0.23		$	0.19	$	0.19		$	0.60	$	0.33		$	0.11		$	(0.01	)	$	0.28		$	0.72

Mark-to-Market (MTM) adjustments:
Reverse forward unrealized MTM gains/losses		(43	)		38		16			11		(221	)		(22	)		141			(70	)		(172	)
Add realized gains/losses from MTM previously recognized		77			100		80			257		113			77			72			48			310

Total MTM adjustments		34			138		96			268		(108	)		55			213			(22	)		138

Tax effect of total MTM adjustments (at 39%)		13			53		37			103		(42	)		21			83			(8	)		53


After tax MTM adjustments		21			85		59			165		(66	)		34			130			(14	)		85

Recurring income from cont. ops available to common shareholders after MTM adjust.	$	157		$	198	$	172		$	527	$	132		$	100		$	125		$	154		$	513
Recurring diluted earnings per share after MTM adj.	$	0.26		$	0.33	$	0.28		$	0.87	$	0.22		$	0.17		$	0.22		$	0.26		$	0.86

weighted average shares — diluted (thousands)		607,073			595,561		609,062			608,045		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.