Exhibit 99.1

News Release

NYSE:WMB

Date: Feb. 22, 2007

Williams Reports Fourth-Quarter and Full-Year 2006 Financial Results

• Record-High NGL Margins Drive 2006 Performance

• Natural Gas Production Rises 21% for Full Year; Fourth Consecutive Year to Replace More Than 200% of Production

• Net Income $308.5 Million for Full Year

• Recurring Adjusted Income Increases 38% to $707.8 Million for Full Year; Up 17% for Fourth Quarter

• Cash Flow From Operations Rises 30% to $1.9 Billion for Full Year

Year-End Summary Financial Information	2006						2005
Per share amounts are reported on a fully diluted basis	millions			per share			millions			per share
Income from continuing operations	$	332.8		$	0.55		$	317.4		$	0.53
Loss from discontinued operations	$	(24.3	)	$	(0.04	)	$	(2.1	)		—
Cumulative effect of change in accounting principle		—			—		$	(1.7	)		—
Net income	$	308.5		$	0.51		$	313.6		$	0.53
Recurring income from continuing operations*	$	520.3		$	0.86		$	427.8		$	0.72
After-tax mark-to-market adjustments	$	187.5		$	0.31		$	85.0		$	0.14
Recurring income from continuing operations — after mark-to-market adjustment*	$	707.8		$	1.17		$	512.8		$	0.86

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

Quarterly Summary Financial Information	4Q 2006						4Q 2005
Per share amounts are reported on a fully diluted basis	millions			per share			millions			per share
Income from continuing operations	$	155.5		$	0.25		$	68.8		$	0.11
Loss from discontinued operations	$	(9.1	)	$	(0.01	)	$	(0.3	)		—
Cumulative effect of change in accounting principle		—			—		$	(1.7	)		—
Net income	$	146.4		$	0.24		$	66.8		$	0.11
Recurring income from continuing operations*	$	158.4		$	0.26		$	168.1		$	0.28
After-tax mark-to-market adjustments	$	22.0		$	0.04		$	(13.8	)	$	(0.02	)
Recurring income from continuing operations — after mark-to-market adjustment*	$	180.4		$	0.30		$	154.3		$	0.26

Williams — Fourth-Quarter 2006 Results — Feb. 22, 2007 — Page 1 of 11

     TULSA, Okla. — Williams (NYSE:WMB) announced 2006 unaudited net income of $308.5 million, or 51 cents per share on a diluted basis, compared with net income of $313.6 million, or 53 cents per share on a diluted basis, for 2005.

     Results for 2006 reflect record-high natural gas liquids (NGL) margins for the year, as well as the company’s continued strong growth in natural gas production. Williams’ average daily production from domestic and international interests increased 21 percent in 2006, surpassing 800 million cubic feet of gas equivalent (MMcfe).

     These benefits were partially offset by lower net realized prices for natural gas, a $167.3 million charge associated with a securities litigation settlement, and higher operations and maintenance costs.

     Results for 2006 also include unrealized mark-to-market losses of $22 million from the Power business, compared with $172 million of unrealized gains in 2005.

     For fourth-quarter 2006, the company reported net income of $146.4 million, or 24 cents per share on a diluted basis, compared with net income of $66.8 million, or 11 cents per share on a diluted basis, for fourth-quarter 2005.

     The net income improvement in the fourth quarter is primarily due to the absence of litigation accruals and certain impairments that occurred during the 2005 period, as well as the benefit of record-high NGL margins. Fourth-quarter 2006 also includes a $40 million favorable impact from the resolution of a federal income tax litigation matter, partially offset by a $16 million after-tax impairment charge related to an international Exploration & Production investment.

     The company reported 2006 income from continuing operations of $332.8 million, or 55 cents per share on a diluted basis, compared with $317.4 million, or 53 cents per share on a diluted basis, in 2005.

     For fourth-quarter 2006, the company reported income from continuing operations of $155.5 million, or 25 cents per share on a diluted basis, compared with $68.8 million, or 11 cents per share on a diluted basis, for fourth-quarter 2005.

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

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

     Recurring income from continuing operations — after adjusting for the mark-to-market effect to reflect income as though mark-to-market accounting had never been applied to Power’s designated hedges and other derivatives — was $707.8 million, or $1.17 per share, for 2006. In 2005, the adjusted recurring income from continuing operations was $512.8 million, or 86 cents per share.

Williams — Fourth-Quarter 2006 Results — Feb. 22, 2007 — Page 2 of 11

     For the fourth quarter of 2006, recurring income from continuing operations — after adjusting for the mark-to-market effect — was $180.4 million, or 30 cents per share, compared with $154.3 million, or 26 cents per share, for the same period in 2005.

     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.

CEO Perspective

     “Our portfolio of natural gas businesses continues to deliver strong performance,” said Steve Malcolm, chairman, president and chief executive officer. “Record-level NGL margins in our Midstream business contributed significantly to our results. While natural gas prices were lower during 2006, oil and natural gas liquids prices were stronger. That helped to balance and strengthen our financial performance.

     “We expect strong NGL margins once again will help support the company’s performance, but at levels that are likely to be less than the record-high margins we experienced last year.

     “We have a strong track record of growing our natural gas production while making significant additions to our reserves. For the fourth year in a row, we’ve replaced our reserves at a rate in excess of 200 percent. In the Piceance Basin, we are continuing to deploy high-tech, high-efficiency equipment and practices to support our accelerated development of production.

     “For us, growing our segment profit and our natural gas reserves and production are major catalysts to deliver additional shareholder value. Other significant value drivers are higher rates for our interstate gas pipelines; more deals to sell power beyond 2010; additional midstream expansions; and the opportunity to raise more low-cost capital through dropdowns to Williams Partners.”

Business Segment Performance

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

     For 2006, Williams’ businesses reported consolidated segment profit of $1.47 billion, compared with $1.28 billion for 2005.

     Higher results for 2006 were driven by extraordinary results in Midstream, along with the absence of certain impairment charges and litigation accruals in 2005. These benefits were partially offset by lower segment profit in Exploration & Production and Gas Pipeline.

     Williams’ businesses reported consolidated segment profit of $367.3 million in the fourth quarter of 2006, compared with $311.9 million in the fourth quarter of 2005.

Williams — Fourth-Quarter 2006 Results — Feb. 22, 2007 — Page 3 of 11

     The fourth-quarter 2006 results are primarily attributable to strong profitability in Midstream, as well as the absence of certain impairment charges and litigation accruals recorded in fourth-quarter 2005. These benefits were offset by a segment profit decrease in Exploration & Production.

     On a basis adjusted to remove the effect of nonrecurring items and mark-to-market accounting, Williams had recurring consolidated segment profit of approximately $1.84 billion in 2006, compared with $1.58 billion for 2005 — an increase of 16 percent. The improvement in 2006 on an adjusted basis is primarily due to Midstream’s extraordinary results, along with significant improvement in Power’s recurring after-mark-to-market adjustment results.

     On a basis adjusted to remove the effect of nonrecurring items and market-to-market accounting, Williams had recurring consolidated segment profit of $407 million in fourth-quarter 2006, compared with $448 million in fourth-quarter 2005. The reduction in consolidated segment profit on an adjusted basis is attributed to lower segment profit in Exploration & Production and Gas Pipeline, partially offset by improved Midstream results.

     For 2006, net cash provided by operating activities was approximately $1.9 billion, compared with approximately $1.45 billion for the same period in 2005. Net cash generated in 2006 was primarily reinvested in the form of capital expenditures, which totaled approximately $2.5 billion in 2006.

Exploration & Production: U.S. Production Up 23% in 2006 From Development Activities

     Exploration & Production, which includes natural gas production and development in the U.S. Rocky Mountains, San Juan Basin and Mid-Continent, and oil and gas development in South America, reported 2006 segment profit of $551.5 million. A year ago, the business reported segment profit of $587.2 million.

     The substantially higher production volumes in 2006 were more than offset by lower average realized prices, higher operating costs, and the absence of $29.6 million of gains from the sale of certain properties in 2005. Higher operating costs reflect an increased number of producing wells and higher well service and industry costs.

     For 2006, combined average daily production from U.S. and international interests was up 21 percent to approximately 803 million cubic feet of gas equivalent (MMcfe), compared with 662 MMcfe for the same period in 2005.

     Daily production solely from interests in the United States increased 23 percent to approximately 752 MMcfe in 2006 from 612 MMcfe in 2005.

     For the fourth quarter of 2006, Exploration & Production reported segment profit of $139.6 million, compared with $206.4 million for the same period last year.

     The significant increases in production volumes in the fourth quarter were more than offset by lower average realized prices and higher operating costs.

Williams — Fourth-Quarter 2006 Results — Feb. 22, 2007 — Page 4 of 11

     During the fourth quarter of 2006, Williams’ U.S. production realized net average prices of $4.45 per thousand cubic feet of gas equivalent (Mcfe) — 21 percent lower than the $5.66 per Mcfe realized in the same period a year ago.

     In a separate announcement today, Williams reported year-end 2006 proved U.S. natural gas reserves of 3.7 trillion cubic feet equivalent, up 9.5 percent from year-end 2005 reserves. Including its international interests, Williams had total proved natural gas and oil reserves of 3.9 trillion cubic feet equivalent at year-end 2006.

     Williams’ activities in 2006 resulted in the total addition of 597 billion cubic feet equivalent in net reserves. Over the past three years, Williams has added over 1.6 trillion cubic feet equivalent in domestic net reserves from drilling activity. For the fourth consecutive year, Williams has replaced more than 200 percent of its reserves.

     U.S. Proved Reserves Reconciliation

     Figures in billion cubic feet equivalent of natural gas. May not add due to rounding.

Proved reserves Dec. 31, 2005	3,382
Acquisitions	41
Divestitures	(1	)
Additions and revisions	557
Production	(277	)
Proved reserves Dec. 31, 2006	3,701

     In 2006, Williams continued to have a drilling success rate of approximately 99 percent. The company drilled 1,783 gross wells, of which 1,770 were successful. In 2005, Williams also achieved a 99 percent success rate, drilling 1,629 gross wells.

     Williams currently has 25 rigs operating in the Piceance Basin of western Colorado — the company’s cornerstone for production and reserves growth.

     Within that fleet are 10 new-generation, high-efficiency drilling rigs specifically designed for conditions in the Piceance Basin. Williams deployed those rigs during 2006.

     Williams plans to invest $1.3 billion to $1.4 billion of capital in Exploration & Production this year. These investments focus primarily on activity designed to increase domestic production by 15 to 20 percent during the year.

     For 2007, Williams expects $700 million to $975 million in segment profit from Exploration & Production. The wide range in guidance reflects the potential volatility of natural gas prices and an assumption of unhedged natural gas prices ranging from $7 to $8.30 (Henry Hub), adjusted for basis differential.

Williams — Fourth-Quarter 2006 Results — Feb. 22, 2007 — Page 5 of 11

Midstream Gas & Liquids: Segment Profit Jumps 40% for Year, 46% in Fourth Quarter

     Midstream, which provides natural gas gathering and processing services, along with natural gas liquids fractionation and storage services and olefins production, reported 2006 segment profit of $658.3 million, compared with $471.2 million in 2005, an increase of 40 percent.

     For the fourth quarter of 2006, Midstream reported segment profit of $163.9 million, compared with $112.4 million for the same period in 2005, an increase of 46 percent.

     The improvement in both year-over-year and quarter-over-quarter results in 2006 primarily reflects increased NGL sales margins; significantly higher production handling volumes and revenues in the deepwater Gulf of Mexico; and higher fee-based gathering and processing revenues. The year-over-year increases were partially offset by approximately $72.7 million in litigation accruals related to a contractual dispute surrounding certain natural gas processing facilities known as Gulf Liquids.

     During 2006, Williams’ sales of NGL equity volumes in the United States generated margins of $441.5 million — 121 percent higher than margins of $199.9 million for 2005. The extraordinary margins during 2006 primarily reflect the gap between higher liquids prices — which typically track closely to crude oil prices — and lower natural gas prices.

     Also for the year, Midstream sold 1.35 billion gallons of NGL equity volumes, compared with equity sales of 1.27 billion gallons in 2005. These equity volumes are retained and subsequently marketed by Williams as payment-in-kind under the terms of certain processing contracts. Total production of NGLs from operated domestic plants also reached record levels, moving from 2.35 billion gallons in 2005 to 2.60 billion gallons in 2006.

     During 2006, Williams installed the fifth cryogenic processing train at our existing gas plant in Opal, Wyo. The plant is currently being commissioned and should be in full operating mode in March 2007. The expansion is designed to boost the plant’s processing capacity by more than 30 percent to 1.45 billion cubic feet per day and produce approximately 67,000 barrels per day of NGLs.

     Williams plans to invest $430 million to $470 million of capital in Midstream in 2007. These investments focus primarily on expanding Williams’ gathering and processing systems in the deepwater Gulf of Mexico and in the western United States. We will continue construction on the extension of our Discovery system to the Tahiti prospect and the 37-mile extension of our oil and gas pipelines from our Devils Tower spar to the Blind Faith prospect located in Mississippi Canyon. In 2007, we will continue working on our Perdido Norte project, which includes oil and gas lines that expand the scale of our existing infrastructure in the western deepwater of the Gulf of Mexico.

     For 2007, Williams expects $450 million to $750 million in segment profit from Midstream. The wide range in guidance reflects the potential market volatility in both natural gas and NGL prices during

Williams — Fourth-Quarter 2006 Results — Feb. 22, 2007 — Page 6 of 11

the year and assumptions of NGL margins consistent with an oil-to-gas price ratio of 7.4 to 9.6 (West Texas Intermediate crude to Henry Hub gas).

Gas Pipeline: Earnings Expected to Increase as New Rates Go Into Effect

     Gas Pipeline, which primarily delivers natural gas to markets along the Eastern Seaboard, in Florida and in the Northwest, reported 2006 segment profit of $467.4 million, compared with the $585.8 million for 2005.

     Results for 2006 were reduced by approximately $77 million in selling, general and administrative cost increases, which stemmed primarily from higher costs for personnel, property insurance and information systems support. In addition, 2005 benefited by $14 million from the resolution of Transco’s fuel-tracker filings.

     For the fourth quarter of 2006, Gas Pipeline reported segment profit of $101 million compared with $92.8 million for the same period in 2005. The increase is primarily due to the absence of fourth-quarter 2005 prior-period accounting and valuation corrections related to inventories, though that benefit was offset somewhat by higher selling, general and administrative expenses in the most recent quarter.

     Northwest Pipeline’s new, higher rates went into effect, subject to refund, on Jan. 1, 2007. During the first quarter of 2007, Williams announced that Northwest Pipeline had filed a stipulation and settlement agreement that resolves all outstanding issues in its pending rate case, subject to Federal Energy Regulatory Commission (FERC) approval.

     The settlement between Northwest Pipeline and the intervening parties in the case, including Northwest’s customers, is supported by the FERC staff and is expected to be uncontested. Williams anticipates the process will be concluded by mid-2007.

     Williams’ Transco system also will benefit from new, higher rates, which go into effect, subject to refund, on March 1, 2007. Transco filed its rate case with the FERC on Aug. 31, 2006. The filing reflects, among other things, current levels of operating costs and rate base.

     Since the beginning of the fourth quarter 2006, Williams has announced the status of a variety of Gas Pipeline projects — most significantly the completion and placement into service of its capacity replacement project in Washington state.

     Williams plans to invest $425 million to $535 million of capital in Gas Pipeline in 2007. About half of these investments are planned for expansion projects, with the majority dedicated to the Leidy-to-Long Island and Potomac projects on the Transco system and the Parachute project on the Northwest Pipeline system. The majority of our non-expansion investments are tied to pipeline integrity projects.

     For 2007, Williams expects $585 million to $655 million in segment profit from Gas Pipeline. The projected increase over 2006 results is principally because of new, higher rates for both the Northwest Pipeline and Transco systems.

Williams — Fourth-Quarter 2006 Results — Feb. 22, 2007 — Page 7 of 11

Power: Contracting Megawatts Past 2010

     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

	YTD
Amounts are reported in millions	2006			2005
Segment loss	$	(210.8	)	$	(256.7	)
Nonrecurring adjustments	$	(7.9	)	$	116.6
Recurring segment loss	$	(218.7	)	$	(140.1	)
Mark-to-market adjustments — net	$	303.6		$	137.7
Recurring segment profit (loss) after MTM adjustments	$	84.9		$	(2.4	)

	4Q
	2006			2005
Segment loss	$	(39.0	)	$	(69.4	)
Nonrecurring adjustments	$	1.3		$	91.7
Recurring segment profit (loss)	$	(37.7	)	$	22.3
Mark-to-market adjustments — net	$	35.6		$	(22.4	)
Recurring segment loss after MTM adjustments	$	(2.1	)	$	(0.1	)

     Power reported a 2006 segment loss of $210.8 million, compared with a segment loss of $256.7 million in 2005. These unadjusted results include the non-cash effect of forward unrealized mark-to-market gains and losses.

     The improvement in 2006 is primarily the result of $99 million in increased accrual earnings, a $15 million higher gain on the sale of certain accounts receivable, and a $125 million increase due primarily to the absence of litigation and impairment accruals that occurred in 2005. These items were partially offset by a $194.3 million unfavorable change in unrealized earnings. The decline in unrealized earnings results primarily from power price decreases on a net long power position in 2006, compared to power price increases on a net long power position in 2005.

     For the key performance measure of recurring segment profit adjusted for the effect of mark-to-market accounting, Power reported $84.9 million in 2006, compared with a loss of $2.4 million in 2005.

Williams — Fourth-Quarter 2006 Results — Feb. 22, 2007 — Page 8 of 11

     The year-over-year improvement on the adjusted basis primarily reflects the benefit of structured power hedges in 2006 along with the sale of certain accounts receivable; those benefits were offset partially by the impact of lower fourth quarter 2006 natural gas inventory withdrawals.

     Power reported a fourth-quarter 2006 segment loss of $39 million, compared with a segment loss of $69.4 million in fourth-quarter 2005. These unadjusted results include the non-cash effect of forward unrealized mark-to-market results.

     The improvement in the fourth quarter of 2006 is primarily the result of the absence of litigation accruals and an impairment charge that occurred during the fourth quarter of 2005, as well as an increase in accrual earnings. These benefits were partially offset by lower unrealized mark-to-market gains and the sale during the fourth-quarter of 2005 of certain accounts receivable.

     For the fourth quarter of 2006, Power reported a recurring segment loss adjusted for the effect of mark-to-market accounting of $2.1 million, compared with a loss of $0.1 million in 2005.

     In 2006, Power generated approximately $93 million in cash flow from operations, largely reflecting positive portfolio cash flows net of selling, general and administrative expenses. In 2005, Power generated approximately $188 million in cash flow from operations, largely the result of positive portfolio cash flows and the return of margin dollars.

     Power also completed a significant number of new power sales contracts in 2006. These contracts increase value and cash-flow certainty and reduce the portfolio’s future exposures to fuel-price and weather volatility.

     In a separate announcement today, Williams announced that its Power business has reached agreements with Southern California Edison that lock in certain of Williams’ future power sales and natural gas purchases beyond 2010.

     For 2007, Williams expects segment results from its Power business to range from a loss of $75 million to break-even, absent the effect of any future unrealized mark-to-market gains or losses.

     On a basis adjusted for the effect of mark-to-market accounting, Williams is lowering the high end of its expectation for Power’s 2007 recurring segment profit by $25 million. The updated range — $50 million to $125 million — is designed to more accurately reflect the ongoing effects of price mitigation on our West portfolio and a less favorable outlook for Northeast heat rates.

Guidance Through 2008

     In 2007, Williams expects $1.9 billion to $2.4 billion in consolidated segment profit and earnings per share of $1.10 to $1.50. Both ranges are presented on a recurring basis adjusted for the effect of mark-to-market accounting and assume natural gas prices and NGL margins as previously referenced for Exploration & Production and Midstream. The ranges also contain an assumption for crude oil pricing in

Williams — Fourth-Quarter 2006 Results — Feb. 22, 2007 — Page 9 of 11

the range of $53 to $73 per barrel. Actual 2006 average market price for crude oil was approximately $66.

     The updated consolidated segment profit guidance is approximately $75 million lower than what the company shared in November 2006. The change reflects Williams’ expectation that NGL margins will be stronger than historical levels, but lower than record-high levels in 2006. Also, the change reflects the company’s expectation that the Exploration & Production business will continue to experience costs that are higher, but that remain more favorable than industry averages.

     In 2008, Williams expects consolidated segment profit of $2.20 billion to $2.88 billion on a recurring basis adjusted for the effect of mark-to-market accounting. The projected improvement over 2007 is primarily the result of expected increases in natural gas production.

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

     The company’s overall capital budget is $2.23 to $2.43 billion for 2007 and $1.85 billion to $2.13 billion for 2008.

Today’s Analyst Call

     Williams’ management will discuss the company’s 2006 financial results and outlook through 2008 during an analyst presentation to be webcast live beginning at 10 a.m. Eastern today.

     Participants are encouraged to access the presentation and corresponding slides via www.williams.com.

     A limited number of phone lines also will be available at (800) 811-0667. International callers should dial (913) 981-4901. Callers should dial in at least 10 minutes prior to the start of the discussion.

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

Form 10-K

     The company expects to file its Form 10-K with the Securities and Exchange Commission during the week of Feb. 26. 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.

Williams — Fourth-Quarter 2006 Results — Feb. 22, 2007 — Page 10 of 11

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

# # #

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

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

Investors are urged to closely consider the disclosures and risk factors in our 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 — Fourth-Quarter 2006 Results — Feb. 22, 2007 — Page 11 of 11

Financial Highlights and Operating Statistics

(UNAUDITED)

Final

December 31, 2006

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

(UNAUDITED)

	2005															2006
(Dollars in millions, except per-share amounts)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			4th 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		$	155.5		$	332.8
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		$	0.25		$	0.55
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		—			—			—			32.1			32.1			—			—			—			—			—
Accrual of contingent refund obligation — TGPL		—			—			—			5.2			5.2			—			—			—			—			—
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			2.3			72.7
Settlement of an international contract dispute		—			—			—			—			—			(6.3	)		—			—			—			(6.3	)
Total Midstream Gas & Liquids nonrecurring items		—			—			—			—			—			(6.3	)		68.0			10.3			2.3			74.3
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			1.3			4.8
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	)		1.3			(7.9	)
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			3.6			64.4
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	)		—			—			—			—			—
Impairment of cost-based investment — Petrowayu (Investing income / loss — Exploration & Production)		—			—			—			—			—			—			—			—			16.4			16.4
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			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)		—			—			—			—			—			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			1.4			22.0
		2.7			(8.6	)		18.8			9.4			22.3			16.5			185.1			4.0			19.8			225.4
Total nonrecurring items		(6.6	)		35.9			(16.7	)		167.5			180.1			8.2			253.1			5.1			23.4			289.8
Tax effect for above items (1)		(2.8	)		10.7			(6.4	)		48.0			49.5			3.4			76.6			1.8			2.8			84.6
Adjustment for nonrecurring excess deferred tax (benefit) provision		—			—			—			(20.2	)		(20.2	)		—			—			—			7.4			7.4
Adjustment for tax benefit related to federal income tax litigation		—			—			—			—			—			—			—			—			(25.1	)		(25.1	)
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		$	158.4		$	520.3
Recurring diluted earnings (loss) per common share	$	0.33		$	0.11			($0.01	)	$	0.28		$	0.72		$	0.23		$	0.19		$	0.19		$	0.26		$	0.86
Weighted-average shares — diluted (thousands)		599,422			578,902			580,735			609,106			605,847			607,073			595,561			609,062			610,352			608,627

(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. The tax rate applied to 3rd and 4th quarter 2006 has been adjusted for the effect of nondeductible expenses associated with the securities litigation settlement and related costs. The tax rate applied to 4th quarter 2006 has also been adjusted for the effect of a nondeductible international impairment.

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.

1

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			4th 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		$	2,770.3		$	11,812.9
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			2,288.7			9,973.6
Selling, general and administrative expenses		73.5			62.7			90.6			98.6			325.4			71.0			109.3			128.0			140.9			449.2
Other (income) expense — net		(1.8	)		21.9			(21.4	)		62.5			61.2			(22.3	)		61.7			(15.8	)		(2.9	)		20.7
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			2,426.7			10,443.5
Equity earnings		17.7			9.8			17.6			20.5			65.6			22.2			23.1			29.9			23.7			98.9
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			367.3			1,468.3
Reclass equity earnings		(17.7	)		(9.8	)		(17.6	)		(20.5	)		(65.6	)		(22.2	)		(23.1	)		(29.9	)		(23.7	)		(98.9	)
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	)		(32.8	)		(132.1	)
Securities litigation settlement and related fees		—			—			—			—			—			(1.2	)		(160.7	)		(3.4	)		(2.0	)		(167.3	)
Operating income		464.0			259.5			144.1			303.5			1,171.1			358.3			75.9			327.0			308.8			1,070.0
Interest accrued		(164.7	)		(164.6	)		(166.0	)		(176.4	)		(671.7	)		(162.8	)		(181.5	)		(162.7	)		(169.1	)		(676.1	)
Interest capitalized		1.1			1.4			1.8			2.9			7.2			3.0			4.0			4.8			5.4			17.2
Investing income (loss)		31.0			(17.2	)		31.1			(21.2	)		23.7			46.9			43.3			50.7			32.1			173.0
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	)		(12.5	)		(40.0	)
Other income (expense) — net		5.5			8.1			(1.1	)		14.6			27.1			8.1			8.0			2.8			7.5			26.4
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			172.2			539.1
Provision (benefit) for income taxes		129.5			41.7			(2.6	)		45.3			213.9			88.3			0.9			100.4			16.7			206.3
Income (loss) from continuing operations		202.2			40.7			5.7			68.8			317.4			131.1			(63.9	)		110.1			155.5			332.8
Income (loss) from discontinued operations		(1.1	)		0.6			(1.3	)		(0.3	)		(2.1	)		0.8			(12.1	)		(3.9	)		(9.1	)		(24.3	)
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			146.4			308.5
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		$	146.4		$	308.5
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		$	0.25		$	0.55
Loss from discontinued operations		—			—			—			—			—			—			(0.02	)		(0.01	)		(0.01	)		(0.04	)
Net income (loss)	$	0.34		$	0.07		$	0.01		$	0.11		$	0.53		$	0.22		$	(0.13	)	$	0.18		$	0.24		$	0.51
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			610,352			608,627
Common shares outstanding at end of period (thousands)		570,501			571,502			572,922			573,592			573,592			595,007			595,562			596,130			597,147			597,147
Market price per common share (end of period)	$	18.81		$	19.00		$	25.05		$	23.17		$	23.17		$	21.39		$	23.36		$	23.87		$	26.12		$	26.12
Common dividends per share	$	0.05		$	0.05		$	0.075		$	0.075		$	0.25		$	0.075		$	0.09		$	0.09		$	0.09		$	0.345

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.

2

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			4th Qtr			Year
Segment profit (loss):
Exploration & Production	$	103.7		$	118.3		$	158.8		$	206.4		$	587.2		$	147.6		$	119.8		$	144.5		$	139.6		$	551.5
Gas Pipeline		167.4			164.5			161.1			92.8			585.8			134.7			122.7			109.0			101.0			467.4
Midstream Gas & Liquids		128.6			109.1			121.1			112.4			471.2			151.5			130.7			212.2			163.9			658.3
Power		114.1			(75.0	)		(226.4	)		(69.4	)		(256.7	)		(22.5	)		(79.6	)		(69.7	)		(39.0	)		(210.8	)
Other		(4.1	)		(60.5	)		(10.1	)		(30.3	)		(105.0	)		1.0			(0.7	)		(0.2	)		1.8			1.9
Total segment profit	$	509.7		$	256.4		$	204.5		$	311.9		$	1,282.5		$	412.3		$	292.9		$	395.8		$	367.3		$	1,468.3
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			2.3			74.3
Power		11.4			13.1			0.4			91.7			116.6			—			—			(9.2	)		1.3			(7.9	)
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		$	3.6		$	64.4
Recurring segment profit (loss):
Exploration & Production		96.1			118.3			137.1			206.4			557.9			147.6			119.8			144.5			139.6			551.5
Gas Pipeline		154.3			142.8			146.9			130.1			574.1			132.7			122.7			109.0			101.0			465.4
Midstream Gas & Liquids		128.6			109.1			121.1			112.4			471.2			145.2			198.7			222.5			166.2			732.6
Power		125.5			(61.9	)		(226.0	)		22.3			(140.1	)		(22.5	)		(79.6	)		(78.9	)		(37.7	)		(218.7	)
Other		(4.1	)		(7.4	)		(10.1	)		(1.2	)		(22.8	)		1.0			(0.7	)		(0.2	)		1.8			1.9
Total recurring segment profit	$	500.4		$	300.9		$	169.0		$	470.0		$	1,440.3		$	404.0		$	360.9		$	396.9		$	370.9		$	1,532.7

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.

3

Exploration & Production
(UNAUDITED)

	2005															2006
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr		Year
Revenues:
Production	$	210.2		$	234.8		$	283.0		$	344.4		$	1,072.4		$	286.8		$	287.9		$	316.1		$	347.0	$	1,237.8
Gas management		28.2			32.6			32.1			52.0			144.9			41.2			28.3			25.3			39.3		134.1
Net nonqualified hedge derivative income (loss)		(0.1	)		0.6			(15.9	)		9.8			(5.6	)		12.8			(1.6	)		1.8			11.0		24.0
International		10.8			11.6			16.3			14.7			53.4			16.0			15.1			16.8			15.8		63.7
Other		(0.1	)		1.9			2.9			(0.7	)		4.0			(0.8	)		12.6			11.1			5.1		28.0
Total revenues		249.0			281.5			318.4			420.2			1,269.1			356.0			342.3			371.1			418.2		1,487.6
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			108.6		361.5
Lease and other operating expenses *		23.8			23.9			28.5			29.0			105.2			30.1			43.8			39.0			46.4		159.3
Operating taxes		21.1			23.9			26.7			29.4			101.1			31.8			28.1			31.1			28.7		119.7
Exploration expenses *		0.9			1.1			1.5			4.1			7.6			4.4			2.4			2.6			7.2		16.6
Gathering expense		5.6			6.0			5.0			8.1			24.7			6.4			7.5			7.6			8.6		30.1
Selling, general and administrative expenses (including International)		17.0			17.7			20.3			24.6			79.6			21.5			28.2			28.2			34.4		112.3
Gas management expenses		28.2			32.6			32.1			52.0			144.9			41.2			28.3			25.3			39.3		134.1
International (excluding DD&A and SG&A)		3.3			3.3			4.7			3.6			14.9			5.5			4.9			5.0			5.9		21.3
Other (income) expense — net		(9.6	)		(1.2	)		(19.8	)		(0.7	)		(31.3	)		(0.6	)		0.7			(1.9	)		4.8		3.0
Total segment costs and expenses		148.8			166.8			165.4			219.7			700.7			213.4			228.4			232.2			283.9		957.9
Equity earnings — International		3.5			3.6			5.8			5.9			18.8			5.0			5.9			5.6			5.3		21.8
Reported segment profit		103.7			118.3			158.8			206.4			587.2			147.6			119.8			144.5			139.6		551.5
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		$	139.6	$	551.5

* 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		76.0		274.4
Net domestic volumes per day (MMcfe/d)		568		604		629		646		612		661		738		780		826		752
Net domestic realized price ($/Mcfe)(1)	$	4.001	$	4.164	$	4.801	$	5.655	$	4.688	$	4.712	$	4.177	$	4.300	$	4.450	$	4.401
Production taxes per Mcfe	$	0.413	$	0.435	$	0.462	$	0.493	$	0.452	$	0.534	$	0.420	$	0.433	$	0.377	$	0.436
Lease and other operating expense per Mcfe	$	0.466	$	0.436	$	0.492	$	0.486	$	0.471	$	0.505	$	0.653	$	0.544	$	0.610	$	0.581

(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	6.1	23.7
Volumes per day (MMcfe/d)	59	61	67	65	63	67	61	65	67	65
Volumes net to Williams (after minority interest) (Bcfe)	4.1	4.3	4.8	4.8	18.0	4.7	4.4	4.7	4.8	18.6
Volumes net to Williams per day (MMcfe/d)	46	48	53	51	49	53	48	51	53	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	80.9	293.1
Volumes net to Williams per day (MMcfe/d)	614	652	682	697	662	714	786	831	879	803

4

Gas Pipeline
(UNAUDITED)

	2005														2006
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr		Year			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
Revenues:
Northwest Pipeline	$	80.3		$	78.9		$	79.6		$	82.7	$	321.5		$	79.6		$	80.0		$	81.0		$	83.7		$	324.3
Transcontinental Gas Pipe Line		254.9			278.1			266.0			292.0		1,091.0			254.3			257.2			253.0			258.1			1,022.6
Other		0.1			—			0.2			—		0.3			0.1			0.1			0.2			0.4			0.8
Total revenues		335.3			357.0			345.8			374.7		1,412.8			334.0			337.3			334.2			342.2			1,347.7
Segment costs and expenses:
Costs and operating expenses		160.4			193.3			177.6			250.7		782.0			177.2			192.8			192.2			203.2			765.4
Selling, general and administrative expenses		18.6			6.8			23.6			35.1		84.1			31.0			35.4			45.1			50.0			161.5
Other (income) expense — net		0.3			0.3			0.5			3.4		4.5			(1.4	)		(3.4	)		(2.4	)		(2.3	)		(9.5	)
Total segment costs and expenses		179.3			200.4			201.7			289.2		870.6			206.8			224.8			234.9			250.9			917.4
Equity earnings		11.4			7.9			17.0			7.3		43.6			7.5			10.7			9.2			9.7			37.1
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			29.0			126.9
Transcontinental Gas Pipe Line		117.9			121.8			107.0			50.1		396.8			95.8			81.3			69.5			63.7			310.3
Other		9.8			6.2			15.0			5.5		36.5			5.6			8.6			7.7			8.3			30.2
Total reported segment profit		167.4			164.5			161.1			92.8		585.8			134.7			122.7			109.0			101.0			467.4
Nonrecurring adjustments:
Northwest Pipeline		—			—			—			—		—			—			—			—			—			—
Transcontinental Gas Pipe Line		(13.1	)		(21.7	)		(14.2	)		37.3		(11.7	)		(2.0	)		—			—			—			(2.0	)
Other		—			—			—			—		—			—			—			—			—			—
Total nonrecurring adjustments		(13.1	)		(21.7	)		(14.2	)		37.3		(11.7	)		(2.0	)		—			—			—			(2.0	)
Recurring segment profit:
Northwest Pipeline		39.7			36.5			39.1			37.2		152.5			33.3			32.8			31.8			29.0			126.9
Transcontinental Gas Pipe Line		104.8			100.1			92.8			87.4		385.1			93.8			81.3			69.5			63.7			308.3
Other		9.8			6.2			15.0			5.5		36.5			5.6			8.6			7.7			8.3			30.2
Total recurring segment profit, pre-tax	$	154.3		$	142.8		$	146.9		$	130.1	$	574.1		$	132.7		$	122.7		$	109.0		$	101.0		$	465.4
Operating statistics
Northwest Pipeline
Throughput (TBtu)		181.2			146.2			152.9			192.6		672.9			179.7			142.7			156.6			196.5			675.5
Average daily transportation volumes (TBtu)		2.0			1.6			1.7			2.1		1.9			2.0			1.6			1.7			2.1			1.9
Average daily firm reserved capacity (TBtu)		2.5			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			457.7			1,858.8
Average daily transportation volumes (TBtu)		6.0			4.7			4.9			5.1		5.2			5.6			4.6			5.1			5.0			5.1
Average daily firm reserved capacity (TBtu)		6.9			6.5			6.4			6.8		6.7			7.0			6.4			6.4			6.7			6.6

5

Midstream Gas & Liquids
(UNAUDITED)

	2005															2006
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
Revenues:
Gathering	$	70.6		$	74.2		$	74.0		$	75.8		$	294.6		$	76.8		$	79.0		$	79.2		$	79.7		$	314.7
Processing		23.5			24.3			25.5			22.9			96.2			24.9			27.4			27.6			29.2			109.1
Venezuela fee revenue		36.5			37.8			40.4			38.8			153.5			38.9			38.0			40.6			36.3			153.8
NGL sales from gas processing		285.1			247.0			244.2			259.0			1,035.3			263.7			292.6			296.6			262.9			1,115.8
Production handling and transportation		18.6			20.4			14.7			20.6			74.3			37.2			33.2			33.0			30.4			133.8
Olefins sales (including Gulf and Canada)		146.6			114.2			121.4			185.3			567.5			148.9			131.4			175.9			155.7			611.9
Trading/marketing sales		588.0			574.4			522.0			578.1			2,262.5			709.0			806.1			863.9			757.9			3,136.9
Other revenues		23.7			33.2			31.7			39.1			127.7			34.4			30.7			28.8			29.5			123.4
		1,192.6			1,125.5			1,073.9			1,219.6			4,611.6			1,333.8			1,438.4			1,545.6			1,381.6			5,699.4
Intrasegment eliminations		(385.6	)		(345.4	)		(319.2	)		(328.7	)		(1,378.9	)		(354.4	)		(394.9	)		(428.6	)		(396.8	)		(1,574.7	)
Total revenues		807.0			780.1			754.7			890.9			3,232.7			979.4			1,043.5			1,117.0			984.8			4,124.7
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			144.8			674.3
Olefins cost of goods sold		118.7			104.0			102.2			163.5			488.4			132.8			108.1			141.2			127.8			509.9
Trading/marketing cost of goods sold		584.0			574.7			510.1			575.8			2,244.6			716.7			799.1			863.4			765.8			3,145.0
Venezuela operating costs		16.1			16.0			17.4			17.6			67.1			16.8			18.1			17.1			19.0			71.0
Operating costs		101.6			101.5			112.8			113.9			429.8			120.6			120.7			134.2			135.4			510.9
Other
Selling, general and administrative expenses		22.9			21.0			23.1			29.3			96.3			23.3			25.2			31.1			31.4			111.0
Other (income) expense — net		2.6			1.7			0.8			(1.7	)		3.4			(17.9	)		70.0			(3.2	)		(2.9	)		46.0
Intrasegment eliminations		(385.5	)		(345.5	)		(319.2	)		(328.7	)		(1,378.9	)		(354.4	)		(394.9	)		(428.6	)		(396.8	)		(1,574.7	)
Total segment costs and expenses		685.5			675.8			636.8			788.0			2,786.1			837.8			919.0			912.1			824.5			3,493.4
Equity earnings		7.1			4.1			3.2			9.2			23.6			9.9			6.2			7.3			3.6			27.0
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			163.9			658.3
Nonrecurring adjustments		—			—			—			—			—			(6.3	)		68.0			10.3			2.3			74.3
Recurring segment profit, pre-tax	$	128.6		$	109.1		$	121.1		$	112.4		$	471.2		$	145.2		$	198.7		$	222.5		$	166.2		$	732.6
Operating statistics
Gathering volumes (TBtu)		315.5			323.6			310.3			303.9			1,253.3			296.9			300.1			292.5			291.9			1,181.4
Gathering rate ($/MMBtu)	$	0.2237		$	0.2292		$	0.2386		$	0.2496		$	0.2351		$	0.2590		$	0.2634		$	0.2708		$	0.2730		$	0.2664
Processing volumes (TBtu)		181.0			184.5			190.3			165.6			721.4			191.8			204.8			210.0			226.5			833.1
Processing rate ($/MMBtu)	$	0.1299		$	0.1316		$	0.1342		$	0.1381		$	0.1334		$	0.1298		$	0.1340		$	0.1314		$	0.1289		$	0.1310
NGL equity sales (million gallons)		398.7			338.3			276.4			255.8			1,269.2			333.7			361.3			334.0			325.8			1,354.8
NGL margin ($/gallon)	$	0.1503		$	0.1318		$	0.1976		$	0.1565		$	0.1569		$	0.1900		$	0.3319		$	0.4183		$	0.3625		$	0.3259
Olefins sales (Ethylene & Propylene) (million lbs)		266.5			265.6			258.1			275.9			1,066.1			259.2			196.8			268.1			263.8			987.9

6

Power
(UNAUDITED)

	2005															2006
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			4th 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		$	1,698.1		$	7,462.1
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			1,698.1		$	7,462.4
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			1,716.8			7,637.9
Selling, general and administrative expenses		16.0			16.9			21.1			10.5			64.5			(4.5	)		18.9			22.2			25.6			62.2
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			1,742.4			7,686.2
Equity Earnings		1.1			0.9			1.0			0.1			3.1			(0.2	)		0.3			7.6			5.3			13.0
Reported segment profit (loss)		114.1			(75.0	)		(226.4	)		(69.4	)		(256.7	)		(22.5	)		(79.6	)		(69.7	)		(39.0	)		(210.8	)
Nonrecurring adjustments		11.4			13.1			0.4			91.7			116.6			—			—			(9.2	)		1.3			(7.9	)
Recurring segment profit (loss), pre-tax	$	125.5		$	(61.9	)	$	(226.0	)	$	22.3		$	(140.1	)	$	(22.5	)	$	(79.6	)	$	(78.9	)	$	(37.7	)	$	(218.7	)
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			1.7			1.7
Sales to other segments		0.6			0.4			0.3			0.3			0.4			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			0.1			0.2
Total managed		2.5			2.4			2.3			2.1			2.3			2.2			2.1			2.5			2.2			2.3
Crude & refined products (MBPD)		—			—			—			—			—			—			—			—			—			—
Power (GWh)		14,832			15,906			21,690			14,559			66,987			11,505			12,949			17,430			11,982			53,866

Additional statistics

Value at risk

	Quarter ended 12/31/2006
	(in Millions)
One day VaR - 95% confidence level
Trading	$	1.4	MM
Non-Trading	$	12.2	MM
Aggregate Earnings VaR	$	3.0	MM

	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	$	120.4	$	120.5
Energy marketers and traders		209.0		455.4
Financial institutions		325.5		325.5
Other		20.4		20.4
	$	675.3	$	921.8
Credit Reserves				(20.3	)
Net Credit Exposure from Derivative Contracts			$	901.5

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	$	3.4
13-36 months		(0.4	)
37-60 months		0.2
61-120 months		—
121+ months		0.1
Total Fair Value		3.3
Non-Trading MTM Derivatives and SFAS 133 Hedges		412.6
Non-Power Business Unit Hedges		20.5
Total Net Derivative Assets and Liabilities	$	436.4

Power Portfolio
(Megawatts)

	Quarter Ended
	12/31/06		12/31/05
Owned		207		207
Contracted		9,708		9,616
Total		9,915		9,823

Credit Support (in Millions)

As of December 31, 2006
Prepays	$	7
Margins	$	(77	)
Adequate Assurance	$	8

7

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			4th Qtr		Year
Capital expenditures:
Exploration & Production	$	158.6		$	182.8	$	211.1	$	230.8	$	783.3	$	310.3		$	283.9	$	384.9		$	442.9	$	1,422.0
Gas Pipeline:
Northwest Pipeline		12.0			29.6		43.2		52.2		137.0		40.3			96.0		177.4			159.1		472.8
Transcontinental Gas Pipe Line		35.7			55.0		80.7		83.1		254.5		46.4			106.7		109.4			75.6		338.1
Other		—			—		—		2.2		2.2		—			—		—			—		—
Total		47.7			84.6		123.9		137.5		393.7		86.7			202.7		286.8			234.7		810.9
Midstream Gas & Liquids		16.3			25.5		32.7		40.7		115.2		70.7			39.3		83.5			63.5		257.0
Power		1.0			0.7		0.4		0.1		2.2		0.6			0.6		(0.1	)		0.1		1.2
Other		(0.7)	*		0.1		1.2		4.0		4.6		—			7.8		1.2			9.1		18.1
Total	$	222.9		$	293.7	$	369.3	$	413.1	$	1,299.0	$	468.3		$	534.3	$	756.3		$	750.3	$	2,509.2
Purchase of investments:
Exploration & Production	$	6.3		$	—	$	0.3	$	—	$	6.6	$	—		$	—	$	—		$	—	$	—
Gas Pipeline		—			—		—		—		—		—			—		4.5			0.7		5.2
Midstream Gas & Liquids		—			35.0		11.5		—		46.5		(3.4	)		0.8		—			2.4		(0.2	)
Other		20.0			20.6		4.5		17.9		63.0		13.1			26.0		4.6			0.2		43.9
Total	$	26.3		$	55.6	$	16.3	$	17.9	$	116.1	$	9.7		$	26.8	$	9.1		$	3.3	$	48.9
Summary:
Exploration & Production	$	164.9		$	182.8	$	211.4	$	230.8	$	789.9	$	310.3		$	283.9	$	384.9		$	442.9	$	1,422.0
Gas Pipeline		47.7			84.6		123.9		137.5		393.7		86.7			202.7		291.3			235.4		816.1
Midstream Gas & Liquids		16.3			60.5		44.2		40.7		161.7		67.3			40.1		83.5			65.9		256.8
Power		1.0			0.7		0.4		0.1		2.2		0.6			0.6		(0.1	)		0.1		1.2
Other		19.3			20.7		5.7		21.9		67.6		13.1			33.8		5.8			9.3		62.0
Total	$	249.2		$	349.3	$	385.6	$	431.0	$	1,415.1	$	478.0		$	561.1	$	765.4		$	753.6	$	2,558.1
Cumulative summary:
Exploration & Production	$	164.9		$	347.7	$	559.1	$	789.9	$	789.9	$	310.3		$	594.2	$	979.1		$	1,422.0	$	1,422.0
Gas Pipeline		47.7			132.3		256.2		393.7		393.7		86.7			289.4		580.7			816.1		816.1
Midstream Gas & Liquids		16.3			76.8		121.0		161.7		161.7		67.3			107.4		190.9			256.8		256.8
Power		1.0			1.7		2.1		2.2		2.2		0.6			1.2		1.1			1.2		1.2
Other		19.3			40.0		45.7		67.6		67.6		13.1			46.9		52.7			62.0		62.0
Total	$	249.2		$	598.5	$	984.1	$	1,415.1	$	1,415.1	$	478.0		$	1,039.1	$	1,804.5		$	2,558.1	$	2,558.1

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

8

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			4th Qtr			Year
Depreciation, depletion and amortization:
Exploration & Production	$	58.6		$	59.4		$	66.4		$	69.8		$	254.2		$	73.0			84.2			94.8			108.2			360.2
Gas Pipeline:
Northwest Pipeline		17.3			17.0			17.9			18.4			70.6			18.5			18.8			19.1			20.2			76.6
Transcontinental Gas Pipe Line		49.4			48.6			49.3			49.4			196.7			50.0			51.7			51.2			52.2			205.1
Total		66.7			65.6			67.2			67.8			267.3			68.5			70.5			70.3			72.4			281.7
Midstream Gas & Liquids		46.0			46.4			49.5			50.1			192.0			49.4			49.9			49.9			52.0			201.2
Power		3.9			3.7			3.6			3.7			14.9			3.2			3.2			2.3			2.0			10.7
Other		3.0			3.0			2.9			2.7			11.6			2.9			2.7			3.1			3.0			11.7
Total	$	178.2		$	178.1		$	189.6		$	194.1		$	740.0		$	197.0		$	210.5		$	220.4		$	237.6		$	865.5
Other selected financial data:
Cash and cash equivalents	$	1,210.0		$	1,297.2		$	1,360.5		$	1,597.2		$	1,597.2		$	1,115.0		$	980.4		$	1,074.6		$	2,268.6		$	2,268.6
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		$	25,402.4		$	25,402.4
Capital structure:
Debt
Current	$	99.5		$	98.6		$	122.4		$	122.6		$	122.6		$	175.7		$	170.7		$	142.3		$	392.1		$	392.1
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		$	7,622.0		$	7,622.0
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		$	6,073.2		$	6,073.2
Debt to debt-plus-equity ratio		59.6	%		59.1	%		60.0	%		58.7	%		58.7	%		55.6	%		55.9	%		55.0	%		56.9	%		56.9	%

9

Adjustment to remove MTM effect

	2006											2005
Dollars in millions except for per share amounts	1Q			2Q		3Q		4Q		Year		1Q			2Q			3Q			4Q			Year
Recurring income from cont. ops available to common shareholders	$	136		$	113	$	113	$	158	$	520	$	198		$	66		$	(5	)	$	168		$	428
Recurring diluted earnings per common share	$	0.23		$	0.19	$	0.19	$	0.26	$	0.86	$	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		22		(221	)		(22	)		141			(70	)		(172	)
Add realized gains/losses from MTM previously recognized		77			100		80		25		282		113			77			72			48			310
Total MTM adjustments		34			138		96		36		304		(108	)		55			213			(22	)		138
Tax effect of total MTM adjustments (at 39%)		13			53		37		14		116		(42	)		21			83			(8	)		53
After tax MTM adjustments		21			85		59		22		188		(66	)		34			130			(14	)		85
Recurring income from cont. ops available to common shareholders after MTM adjust.	$	157		$	198	$	172	$	180	$	708	$	132		$	100		$	125		$	154		$	513
Recurring diluted earnings per share after MTM adj.	$	0.26		$	0.33	$	0.28	$	0.30	$	1.17	$	0.22		$	0.17		$	0.22		$	0.26		$	0.86
weighted average shares — diluted (thousands)		607,073			595,561		609,062		610,352		608,627		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.

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

Non-GAAP Utility Statement:

     This press release includes certain financial measures, EBITDA, operating 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. 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 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. Prior to the third quarter 2004, the Company did not qualify for hedge accounting with respect to its Power segment. In September 2004, we announced our decision to continue operating the Power business. As a result of that decision, Power’s derivative contracts became eligible 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 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 Power 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.