e8vk

-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, PBIdEW/h/N5VHS735NmVs0c8/8qdzI3G122ehjfEOPKHaay4IWpNk83ggVj4XKBa mucc7eJLn5KQ71tiND7RqA== 0000950134-07-010035.txt : 20070503 0000950134-07-010035.hdr.sgml : 20070503 20070503074635 ACCESSION NUMBER: 0000950134-07-010035 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20070503 ITEM INFORMATION: Results of Operations and Financial Condition ITEM INFORMATION: Financial Statements and Exhibits FILED AS OF DATE: 20070503 DATE AS OF CHANGE: 20070503 FILER: COMPANY DATA: COMPANY CONFORMED NAME: WILLIAMS COMPANIES INC CENTRAL INDEX KEY: 0000107263 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 730569878 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-04174 FILM NUMBER: 07812843 BUSINESS ADDRESS: STREET 1: ONE WILLIAMS CTR CITY: TULSA STATE: OK ZIP: 74172 BUSINESS PHONE: 9185732000 MAIL ADDRESS: STREET 1: ONE WILLIAM CENTER CITY: TULSA STATE: OK ZIP: 74172 FORMER COMPANY: FORMER CONFORMED NAME: WILLIAMS BROTHERS COMPANIES DATE OF NAME CHANGE: 19710817 8-K 1 d46207e8vk.htm FORM 8-K e8vk

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

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

Date of Report (Date of earliest event reported): May 3, 2007

The Williams Companies, Inc.

(Exact name of registrant as specified in its charter)


Delaware	1-4174	73-0569878

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


One Williams Center, Tulsa, Oklahoma		74172

(Address of principal executive offices)		(Zip Code)

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

Not Applicable

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

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

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

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

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

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


Item 2.02.		Results of Operations and Financial Condition.

On May 3, 2007, The Williams Companies, Inc. (“Williams” or the “Company”) issued a press release announcing its financial results for the quarter ended March 31, 2007. A copy of the press release and its accompanying highlights and reconciliation schedules are furnished as a part of this current report on Form 8-K as Exhibit 99.1 and is incorporated herein in its entirety by reference.

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


Item 9.01.		Financial Statements and Exhibits.


(a)		None

(b)		None

(c)		None

(d)		Exhibits


Exhibit 99.1		Copy of Williams’ press release dated May 3, 2007, and its accompanying highlights and reconciliation schedules, publicly announcing its first quarter 2007 financial results.

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


	THE WILLIAMS COMPANIES, INC.

Date: May 3, 2007	/s/ Donald R. Chappel

	Name:	Donald R. Chappel
	Title:	Senior Vice President and Chief
		Financial Officer

INDEX TO EXHIBITS


EXHIBIT
NUMBER		DESCRIPTION

Exhibit 99.1		Copy of Williams’ press release dated May 3, 2007, and its accompanying highlights and reconciliation schedules, publicly announcing its first quarter 2007 financial results.

EX-99.1 2 d46207exv99w1.htm COPY OF PRESS RELEASE exv99w1


NewsRelease
NYSE: WMB

Date: May 3, 2007

Williams Reports First-Quarter 2007 Financial Results

	•		Natural Gas Production Growth, New Pipeline Rates Drive First Quarter Performance

	•		U.S. Production Up 28%; Piceance Basin Production Up 37%

	•		Natural Gas Liquid Margins Remain Near Historic Highs

	•		Net Income of $134.0 Million in First Quarter

	•		Quarterly Recurring Adjusted Income Up 12% to $176.4 Million

Quarterly Summary Financial Information


	1Q 2007				1Q 2006
Per share amounts are reported on a fully diluted basis	millions		per share		millions		per share
Income from continuing operations	$	131.8	$	0.22	$	131.1	$	0.22

Income from discontinued operations	$	2.2		–	$	0.8		—


Net income	$	134.0	$	0.22	$	131.9	$	0.22


Recurring income from continuing operations*	$	127.8	$	0.21	$	135.9	$	0.23

After-tax mark-to-market adjustments	$	48.6	$	0.08	$	21.1	$	0.03


Recurring income from continuing operations — after mark-to-market adjustment*	$	176.4	$	0.29	$	157.0	$	0.26


*		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.

TULSA, Okla. – Williams (NYSE:WMB) announced unaudited first-quarter 2007 net income of $134.0 million, or 22 cents per share on a diluted basis, compared with net income of $131.9 million, or 22 cents per share on a diluted basis, for first-quarter 2006.

First-quarter 2007 results benefited from the company’s continued strong growth in natural gas production, along with higher net realized average prices for natural gas sales. Average daily domestic production increased 28 percent compared with first-quarter 2006, while production in the Piceance Basin in western Colorado increased 37 percent.

The quarter also benefited from new, higher rates on both the Transco and Northwest interstate gas pipeline systems and continued strong natural gas liquid (NGL) margins. Higher operating and maintenance costs partially offset these benefits.

The company’s strong operational performance in the first quarter was also offset by the year-

Williams — First Quarter 2007 Results — May 3, 2007 — Page 1 of 9

over-year net difference in unrealized mark-to-market results. First-quarter 2007 included $70.6 million in unrealized mark-to-market losses for the Power business, compared with $43.0 million in unrealized mark-to-market gains in Power during first-quarter 2006 – a net difference of $113.6 million.

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 $176.4 million, or 29 cents per share, for first-quarter 2007. For first-quarter 2006, the adjusted recurring income from continuing operations was $157.0 million, or 26 cents per share.

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

“In the first quarter of 2007, Williams delivered results on a number of fronts that we have outlined as catalysts for increasing shareholder value,” said Steve Malcolm, chairman, president and chief executive officer.

“Our development efforts resulted in robust natural gas production growth, particularly in the Piceance Basin. We also have a 10-year-plus inventory of available drilling locations, providing a solid foundation for future growth.

“Also in the first quarter, we began enjoying the benefit of new, higher rates for both the Northwest and Transco gas pipelines that are more in line with current costs and rate base. The new rates were a major driver for Gas Pipeline’s performance in the first quarter and will continue to be as we move forward.

“Our Midstream projects should continue to drive significant value – from the recently completed expansion of the Opal gas plant to the medium- and longer-term projects such as the expansions in the deepwater Gulf of Mexico and entry into the Piceance Basin.”

Business Segment Performance

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

Williams — First Quarter 2007 Results — May 3, 2007 — Page 2 of 9

For first-quarter 2007, Williams’ businesses reported consolidated segment profit of $411.4 million, compared to $412.3 million for first-quarter 2006.

First-quarter 2007 reflects improved results in the Exploration & Production and Gas Pipelines business units, which was offset by lower segment profit in Power related to unrealized mark-to-market losses.

On a basis adjusted to remove the effect of nonrecurring items and mark-to-market accounting, Williams had recurring consolidated segment profit of approximately $482 million in first quarter 2007, compared with $438 million for first-quarter 2006 — an increase of 10 percent.

The improvement in consolidated segment profit on an adjusted basis is attributed to improved segment profit in Exploration & Production and Gas Pipelines.

Exploration & Production: 28% Domestic Production Growth Drives 27% Improvement in Segment Profit

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 first-quarter 2007 segment profit of $188.1 million. In the same period last year, the business reported segment profit of $147.6 million.

The improved results in the first quarter reflect continued strong growth in natural gas production volumes, along with higher net realized average natural gas prices. Higher operating expenses and depletion, depreciation and amortization costs during first-quarter 2007 partially offset these improvements.

For first-quarter 2007, combined average daily production from U.S. and international interests was up 25 percent to approximately 891 million cubic feet (MMcfe) of gas equivalent, compared with 714 MMcfe for the same period in 2006.

Daily production solely from interests in the United States increased 28 percent to approximately 845 MMcfe in first quarter 2007 from 661 MMcfe in first-quarter 2006.

During the first quarter of 2007, Williams’ U.S. production realized net average prices of $5.32 per thousand cubic feet (Mcfe) of gas equivalent — 13 percent higher than the $4.71 per Mcfe realized in the same period a year ago. Net realized average prices include market prices, net of fuel and shrink and hedge positions, less gathering and transportation expenses.

Williams also has increased the company’s total proved, probable and possible reserves to an estimated 10.8 trillion cubic feet equivalent (Tcfe) from the previous estimate of 10.7 Tcfe, after producing 0.3 Tcfe in 2006. Total reserves are comprised of primarily domestic interests.

Williams — First Quarter 2007 Results — May 3, 2007 — Page 3 of 9

In the Piceance Basin of western Colorado — the company’s cornerstone for production and reserves growth – first-quarter 2007 average daily net production was 478 MMcfe per day – a 37 percent increase over year-ago levels. Williams currently has 25 rigs in operation in the Piceance Basin, four more than the same time last year. Within that fleet are 10 new-generation, high-efficiency drilling rigs specifically designed for conditions in the Piceance Basin.

For 2007, Williams continues to expect $700 million to $975 million in segment profit from Exploration & Production.

Midstream Gas & Liquids: Strong NGL Margins Continue to Drive Segment Profit

Midstream, which provides natural gas gathering and processing services, along with natural gas liquids fractionation and storage services and olefins production, reported a first-quarter 2007 segment profit of $154.0 million compared with $151.5 million in the first quarter of 2006.

The slight improvement in Midstream’s first-quarter results is due to NGL sales margins remaining at historically high levels. Increased expenses and deepwater Gulf of Mexico volumes moderating from higher-than-normal levels in first-quarter 2006 partially offset the benefit of the strong NGL margins.

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

In first-quarter 2007, Midstream sold 344.6 million gallons of NGL equity volumes, an increase of 3 percent compared with equity sales of 333.7 million gallons in the prior-year period. The new TXP5 train at the Opal, Wyo., gas processing plant contributed to higher volumes in the West, which were offset by lower volumes in the Gulf caused by intermittent periods of unfavorable market commodity prices.

Combined revenues for both gathering and fee-based processing were slightly higher year-over-year. Processing fee volumes were 226.9 British thermal units (TBtu) in first-quarter 2007, compared with 191.8 TBtu in the 2006 period. Gathering volumes in first-quarter 2007 were 269.3 trillion TBtu, compared with 296.9 TBtu in the 2006 period.

The previously referenced TXP5 cryogenic processing train at the Opal plant reached full operating mode in February 2007. The expansion was 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.

During the first quarter, Williams’ midstream business announced its entry into the Piceance Basin with plans to construct and operate a 450-million-cubic-feet-per-day natural gas processing plant. Located in western Colorado, the Piceance Basin is where the company has its most significant volume of natural gas production, reserves and development activity.

Coupled with the existing E&P infrastructure, the new Willow Creek plant will provide a growth platform for the company’s midstream business in the area. Williams expects initial operations at the new

Williams — First Quarter 2007 Results — May 3, 2007 — Page 4 of 9

plant to boost the volume of marketable liquids recovered from its production in the basin by an additional 20,000 barrels per day. The planned 150-mile extension of the Overland Pass Pipeline, in which Williams has an interest, will transport the NGL liquids already being produced by the company’s existing facilities and the Willow Creek plant to Midcontinent markets.

For 2007, Williams has increased its previous guidance for Midstream segment profit by $50 million, narrowing the range of its expected results. The new range — $500 million to $750 million – is primarily the result of realized first-quarter margins from the company’s NGL sales as well as a stronger outlook for second quarter.

Gas Pipeline: 1Q Segment Profit Up on New Rates

Gas Pipeline, which primarily delivers natural gas to markets along the Eastern Seaboard, the Northwest, and Florida, reported first quarter 2007 segment profit of $149.7 million, compared with $134.7 million for first-quarter 2006.

The increase in quarterly profit was primarily due to increased revenue resulting from the Northwest Pipeline and Transco rate cases. Increased costs, including higher operating expenses and higher selling, general and administrative costs, partially offset the quarterly improvement.

Northwest Pipeline’s new, higher rates went into effect on Jan. 1, 2007. On March 30, the Federal Energy Regulatory Commission (FERC) approved Northwest Pipeline’s stipulation and settlement agreement that resolved all outstanding issues in the rate case.

Transco’s new, higher rates went into effect, subject to refund, on March 1, 2007. Transco filed its rate case with the FERC on Aug. 31, 2006. Transco has begun meeting with FERC staff and its customers to discuss a settlement of the rate case.

The filings of both rate cases reflect, among other things, updated levels of operating costs and rate base.

For 2007, Williams continues to expect $585 million to $655 million in segment profit from Gas Pipeline.

Williams — First Quarter 2007 Results — May 3, 2007 — Page 5 of 9

Power: Continues to Execute Deals as Market Fundamentals Improve

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


	1Q
Amounts in Millions	2007			2006
Segment loss	$	(81.1	)	$	(22.5	)
Nonrecurring adjustments		—			—

Recurring segment loss	$	(81.1	)	$	(22.5	)
Mark-to-market adjustments — net	$	78.6		$	34.1

Recurring segment profit (loss) after MTM adjustments	$	(2.5	)	$	11.6

Power reported a first-quarter 2007 segment loss of $81.1 million, compared with a segment loss of $22.5 million in first quarter 2006. These unadjusted results include the non-cash effect of forward unrealized mark-to-market gains and losses.

The wider loss in first-quarter 2007 reflects a $70.6 million unrealized mark-to-market loss, compared to a $43.0 million unrealized mark-to-market gain during first-quarter 2006 – a net unrealized difference of $113.6 million. The results also reflect the absence of income from an accounts receivable sale during first-quarter 2006. An improvement in accrual results partially offset the lower results.

On a basis adjusted for the effect of mark-to-market accounting, Power reported a recurring segment loss of $2.5 million in first-quarter 2007, compared with a recurring segment profit of $11.6 million in the same period last year.

The year-over-year decline on the adjusted basis primarily reflects the absence of the previously noted accounts receivable sale that occurred in the first quarter of 2006.

As the power market fundamentals improve, Power continues to execute new power sales contracts. These contracts increase value and cash-flow certainty and reduce the portfolio’s future exposures to commodity-price and weather volatility.

To date in 2007, Power has completed several new agreements, including the contract with Southern California Edison that was announced in February. Those deals increase the certainty of expected cash flows and profits for 2008-2011.

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

On a basis adjusted for the effect of mark-to-market accounting, Williams continues to expect $50 million to $125 million in recurring segment profit.

Williams — First-Quarter 2007 Results – May 3, 2007 — Page 6 of 9

Guidance Through 2008

For 2007, Williams has increased its guidance by $50 million, narrowing the range of its expected results. The new range — $1.95 billion to $2.4 billion in consolidated segment profit and earnings per share of $1.15 to $1.50 – reflects the previously referenced increase in guidance for Midstream. Both ranges are presented on a recurring basis adjusted for the effect of mark-to-market accounting.

The 2007 ranges also assume unhedged natural gas prices ranging from $7 to $8.30 per Mcfe (Henry Hub), adjusted for basis differential, NGL margins consistent with an oil-to-gas price ratio of 7.4 to 9.6 (West Texas Intermediate crude to Henry Hub gas), and an assumption for crude oil pricing in the range of $53 to $73 per barrel.

In 2008, Williams continues to expect consolidated segment profit of $2.13 billion to $2.98 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.

Williams has also increased its previous guidance on capital expenditures for 2007 and 2008 to reflect Midstream expansion projects, including Willow Creek.

In 2007, the company now expects $550 million to $600 million in capital expenditures for Midstream, which increases total expected capital expenditures for the company to $2.35 billion to $2.55 billion.

In 2008, the updated ranges are $475 million to $525 million for Midstream and $2.08 billion to $2.35 billion for the company.

Today’s Analyst Call

Williams’ management will discuss the company’s first-quarter 2007 financial results and outlook through 2008 during an analyst presentation to be webcast live beginning at 10 a.m. Eastern today.

Participants are encouraged to access the presentation and corresponding slides via www.williams.com. A limited number of phone lines also will be available at (800) 279-9534. International callers should dial (719) 457-2685. Callers should dial in at least 10 minutes prior to the start of the discussion. Replays of the webcast will be available at www.williams.com for two weeks following the event.

Form 10-Q

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

Williams — First-Quarter 2007 Results — May 3, 2007 — Page 7 of 9

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. Click here to join our e-mail list.


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

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

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

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

###

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

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves. We have used certain

Williams — First-Quarter 2007 Results — May 3, 2007 — Page 8 of 9

terms in this news release such as “probable” reserves and “possible” reserves and “unrisked theoretical resource estimates” that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated hydrocarbon quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under the assumed economic conditions. Probable and possible reserves are estimates of potential reserves that are made using accepted geological and engineering analytical techniques, but which are estimated with reduced levels of certainty than for proved reserves. Generally under such techniques, probable reserve estimates are more than 50% certain and possible reserve estimates are less than 50% but more than 10% certain. Unrisked theoretical resource estimates are even less certain than those for possible reserves and are not risk adjusted. Unrisked theoretical resource estimates include (i) an estimate of hydrocarbon quantities for new areas for which we do not have sufficient information to date to classify the resources as probable or even possible reserves and (ii) the amount by which we have reduced our probable and possible reserves for existing areas to take into account the reduced level of certainty of recovery of the resources. Unlike probable and possible reserves, unrisked theoretical resource estimates do not take into account the uncertainty of resource recovery and, therefore, are not indicative of the expected future recovery and should not be relied upon.

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

Investors are urged to closely consider the disclosures and risk factors in our annual report on Form 10-K filed with the Securities and Exchange Commission on Feb. 28, 2007, and our quarterly reports on Form 10-Q available from our offices or from our website at www.williams.com.

Williams — First-Quarter 2007 Results — May 3, 2007 — Page 9 of 9

Financial Highlights and Operating Statistics
(UNAUDITED)

Final

March 31, 2007

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


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

Income (loss) from continuing operations available to common stockholders	$	131.1		$	(63.9	)	$	110.1		$	155.5		$	332.8		$	131.8


Income (loss) from continuing operations — diluted earnings (loss) per common share	$	0.22		$	(0.11	)	$	0.19		$	0.25		$	0.55		$	0.22


Nonrecurring items:

Gas Pipeline
Reversal of litigation contigency due to favorable ruling — TGPL		(2.0	)		—			—			—			(2.0	)		—

Total Gas Pipeline nonrecurring items		(2.0	)		—			—			—			(2.0	)		—

Midstream Gas & Liquids
Reversal of a maintenance accrual		—			—			—			—			—			(7.9	)
Gains on sales of MGL properties		—			—			(7.9	)		—			(7.9	)		—
Adjustment of accounts payable accrual		—			—			10.6			—			10.6			—
Losses on asset retirements 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)	⁽¹⁾		—			—			—			(6.3	)		—

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

Power
Reduction of contingent obligations associated with our former distributive power generation business		—			—			(12.7	)		—			(12.7	)		—
Accrual for litigation contingencies ⁽¹⁾		—			—			3.5			1.3			4.8			—

Total Power nonrecurring items		—			—			(9.2	)		1.3			(7.9	)		—
Nonrecurring items below segment profit (loss)
Impairment of cost-based investment — Petrowayu (Investing income / loss — Exploration & Production)		—			—			—			16.4			16.4			—
Securities litigation settlement and related costs ⁽¹⁾		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			1.4

		16.5			185.1			4.0			19.8			225.4			1.4

Total nonrecurring items		8.2			253.1			5.1			23.4			289.8			(6.5	)
Tax effect for above items ⁽¹⁾		3.4			76.6			1.8			2.8			84.6			(2.5	)
Adjustment for nonrecurring excess deferred tax provision		—			—			—			7.4			7.4			—
Adjustment for tax benefit related to federal income tax litigation		—			—			—			(25.1	)		(25.1	)		—


Recurring income from continuing operations available to common stockholders	$	135.9		$	112.6		$	113.4		$	158.4		$	520.3		$	127.8


Recurring diluted earnings per common share	$	0.23		$	0.19		$	0.19		$	0.26		$	0.86		$	0.21


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


⁽¹⁾		The tax rate applied to Midstream’s international contract dispute settlement in 1st quarter 2006 is 34%. The tax rate applied to nonrecurring items for 2nd quarter 2006 has been adjusted for the effect of 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.

Consolidated Statement of Income
(UNAUDITED)


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

Revenues	$	3,027.5		$	2,715.1		$	3,300.0		$	2,770.3		$	11,812.9		$	2,852.1

Segment costs and expenses:
Costs and operating expenses		2,588.7			2,273.8			2,822.4			2,288.7			9,973.6			2,362.7
Selling, general and administrative expenses		71.0			109.3			128.0			140.9			449.2			117.5
Other (income) expense — net		(22.3	)		61.7			(15.8	)		(2.9	)		20.7			(18.1	)

Total segment costs and expenses		2,637.4			2,444.8			2,934.6			2,426.7			10,443.5			2,462.1


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

Total segment profit		412.3			292.9			395.8			367.3			1,468.3			411.4


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


Operating income		358.3			75.9			327.0			308.8			1,070.0			350.6

Interest accrued		(162.8	)		(181.5	)		(162.7	)		(169.1	)		(676.1	)		(173.3	)
Interest capitalized		3.0			4.0			4.8			5.4			17.2			4.9
Investing income		46.9			43.3			50.7			32.1			173.0			43.7
Early debt retirement costs		(27.0	)		(4.4	)		—			—			(31.4	)		—
Minority interest in income of consolidated subsidiaries		(7.1	)		(8.3	)		(12.1	)		(12.5	)		(40.0	)		(14.0	)
Other income — net		8.1			8.0			2.8			7.5			26.4			2.0


Income (loss) from continuing operations before income taxes		219.4			(63.0	)		210.5			172.2			539.1			213.9
Provision for income taxes		88.3			0.9			100.4			16.7			206.3			82.1


Income (loss) from continuing operations		131.1			(63.9	)		110.1			155.5			332.8			131.8
Income (loss) from discontinued operations		0.8			(12.1	)		(3.9	)		(9.1	)		(24.3	)		2.2


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


Diluted earnings per common share:
Income (loss) from continuing operations	$	0.22		$	(0.11	)	$	0.19		$	0.25		$	0.55		$	0.22
Income (loss) from discontinued operations		—			(0.02	)		(0.01	)		(0.01	)		(0.04	)		—


Net income (loss)	$	0.22		$	(0.13	)	$	0.18		$	0.24		$	0.51		$	0.22


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

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

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

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


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.

Reconciliation of Segment Profit to Recurring Segment Profit
(UNAUDITED)


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

Segment profit (loss):

Exploration & Production	$	147.6		$	119.8		$	144.5		$	139.6		$	551.5		$	188.1
Gas Pipeline		134.7			122.7			109.0			101.0			467.4			149.7
Midstream Gas & Liquids		151.5			130.7			212.2			163.9			658.3			154.0
Power		(22.5	)		(79.6	)		(69.7	)		(39.0	)		(210.8	)		(81.1	)
Other		1.0			(0.7	)		(0.2	)		1.8			1.9			0.7

Total segment profit	$	412.3		$	292.9		$	395.8		$	367.3		$	1,468.3		$	411.4


Nonrecurring adjustments:

Exploration & Production	$	—		$	—		$	—		$	—		$	—		$	—
Gas Pipeline		(2.0	)		—			—			—			(2.0	)		—
Midstream Gas & Liquids		(6.3	)		68.0			10.3			2.3			74.3			(7.9	)
Power		—			—			(9.2	)		1.3			(7.9	)		—
Other		—			—			—			—			—			—

Total segment nonrecurring adjustments	$	(8.3	)	$	68.0		$	1.1		$	3.6		$	64.4		$	(7.9	)


Recurring segment profit (loss):

Exploration & Production	$	147.6		$	119.8		$	144.5		$	139.6		$	551.5		$	188.1
Gas Pipeline		132.7			122.7			109.0			101.0			465.4			149.7
Midstream Gas & Liquids		145.2			198.7			222.5			166.2			732.6			146.1
Power		(22.5	)		(79.6	)		(78.9	)		(37.7	)		(218.7	)		(81.1	)
Other		1.0			(0.7	)		(0.2	)		1.8			1.9			0.7

Total recurring segment profit	$	404.0		$	360.9		$	396.9		$	370.9		$	1,532.7		$	403.5


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)


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

Revenues:
Production	$	286.8		$	287.9		$	316.1		$	347.0	$	1,237.8	$	413.2
Gas management		41.2			28.3			25.3			39.3		134.1		55.3
Net nonqualified hedge derivative income (loss)		12.8			(1.6	)		1.8			11.0		24.0		(2.2	)
International		16.0			15.1			16.8			15.8		63.7		14.5
Other		(0.8	)		12.6			11.1			5.1		28.0		1.9

Total revenues		356.0			342.3			371.1			418.2		1,487.6		482.7

Segment costs and expenses:
Depreciation, depletion and amortization (including International)		73.1			84.5			95.3			108.6		361.5		113.6
Lease and other operating expenses *		30.1			43.8			39.0			46.4		159.3		43.7
Operating taxes		31.8			28.1			31.1			28.7		119.7		33.5
Exploration expenses *		4.4			2.4			2.6			7.2		16.6		6.9
Gathering expense		6.4			7.5			7.6			8.6		30.1		8.6
Selling, general and administrative expenses (including International)		21.5			28.2			28.2			34.4		112.3		35.9
Gas management expenses		41.2			28.3			25.3			39.3		134.1		55.3
International (excluding DD&A and SG&A)		5.5			4.9			5.0			5.9		21.3		4.3
Other (income) expense — net		(0.6	)		0.7			(1.9	)		4.8		3.0		(1.9	)

Total segment costs and expenses		213.4			228.4			232.2			283.9		957.9		299.9

Equity earnings — International		5.0			5.9			5.6			5.3		21.8		5.3


Reported segment profit		147.6			119.8			144.5			139.6		551.5		188.1

Nonrecurring adjustments		—			—			—			—		—		—


Recurring segment profit, pre-tax	$	147.6		$	119.8		$	144.5		$	139.6	$	551.5	$	188.1


*		Amounts have been reclassified to the current classifications.

Operating statistics


Domestic:
Total domestic net volumes (Bcfe)		59.5		67.1		71.8		76.0		274.4		76.1
Net domestic volumes per day (MMcfe/d)		661		738		780		826		752		845
Net domestic realized price ($/Mcfe) (1)	$	4.712	$	4.177	$	4.300	$	4.450	$	4.401	$	5.318
Production taxes per Mcfe	$	0.534	$	0.420	$	0.433	$	0.377	$	0.436	$	0.440
Lease and other operating expense per Mcfe	$	0.505	$	0.653	$	0.544	$	0.610	$	0.581	$	0.574


(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)	6.0	5.6	6.0	6.1	23.7	5.2
Volumes per day (MMcfe/d)	67	61	65	67	65	58

Volumes net to Williams (after minority interest)(Bcfe)	4.7	4.4	4.7	4.8	18.6	4.1
Volumes net to Williams per day (MMcfe/d)	53	48	51	53	51	46

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

Gas Pipeline
(UNAUDITED)


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

Revenues:
Northwest Pipeline	$	79.6		$	80.0		$	81.0		$	83.7		$	324.3		$	103.0
Transcontinental Gas Pipe Line		254.3			257.2			253.0			258.1			1,022.6			267.6
Other		0.1			0.1			0.2			0.4			0.8			0.2

Total revenues		334.0			337.3			334.2			342.2			1,347.7			370.8

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

Total segment costs and expenses		206.8			224.8			234.9			250.9			917.4			230.4

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


Reported segment profit:
Northwest Pipeline		33.3			32.8			31.8			29.0			126.9			54.9
Transcontinental Gas Pipe Line		95.8			81.3			69.5			63.7			310.3			87.1
Other		5.6			8.6			7.7			8.3			30.2			7.7

Total reported segment profit		134.7			122.7			109.0			101.0			467.4			149.7

Nonrecurring adjustments:
Northwest Pipeline		—			—			—			—			—			—
Transcontinental Gas Pipe Line		(2.0	)		—			—			—			(2.0	)		—
Other		—			—			—			—			—			—

Total nonrecurring adjustments		(2.0	)		—			—			—			(2.0	)		—

Recurring segment profit:
Northwest Pipeline		33.3			32.8			31.8			29.0			126.9			54.9
Transcontinental Gas Pipe Line		93.8			81.3			69.5			63.7			308.3			87.1
Other		5.6			8.6			7.7			8.3			30.2			7.7

Total recurring segment profit, pre-tax	$	132.7		$	122.7		$	109.0		$	101.0		$	465.4		$	149.7


Operating statistics

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

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

Midstream Gas & Liquids
(UNAUDITED)


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

Revenues:
Gathering & Processing	$	101.7		$	106.4		$	106.8		$	108.9		$	423.8		$	104.0
Venezuela fee revenue		38.9			38.0			40.6			36.3			153.8			37.3
NGL sales from gas processing		263.7			292.6			296.6			262.9			1,115.8			260.0
Production handling and transportation		37.2			33.2			33.0			30.4			133.8			28.8
Olefins sales (including Gulf and Canada)		148.9			131.4			175.9			155.7			611.9			131.0
Trading/marketing sales		709.0			806.1			863.9			757.9			3,136.9			792.1
Other revenues		34.4			30.7			28.8			29.5			123.4			26.5

		1,333.8			1,438.4			1,545.6			1,381.6			5,699.4			1,379.7
Intrasegment eliminations		(354.4	)		(394.9	)		(428.6	)		(396.8	)		(1,574.7	)		(384.3	)

Total revenues		979.4			1,043.5			1,117.0			984.8			4,124.7			995.4
Segment costs and expenses:
NGL cost of goods sold		199.9			172.7			156.9			144.8			674.3			165.5
Olefins cost of goods sold		132.8			108.1			141.2			127.8			509.9			114.2
Trading/marketing cost of goods sold		716.7			799.1			863.4			765.8			3,145.0			787.4
Venezuela operating costs		16.8			18.1			17.1			19.0			71.0			18.8
Operating costs		120.6			120.7			134.2			135.4			510.9			134.2
Other
Selling, general and administrative expenses		23.3			25.2			31.1			31.4			111.0			27.2
Other (income) expense — net		(17.9	)		70.0			(3.2	)		(2.9	)		46.0			(14.9	)
Intrasegment eliminations		(354.4	)		(394.9	)		(428.6	)		(396.8	)		(1,574.7	)		(384.3	)

Total segment costs and expenses		837.8			919.0			912.1			824.5			3,493.4			848.1
Equity earnings		9.9			6.2			7.3			3.6			27.0			6.7
Income from investments		—			—			—			—			—			—

Reported segment profit		151.5			130.7			212.2			163.9			658.3			154.0
Nonrecurring adjustments		(6.3	)		68.0			10.3			2.3			74.3			(7.9	)

Recurring segment profit, pre-tax	$	145.2		$	198.7		$	222.5		$	166.2		$	732.6		$	146.1


Operating statistics

Gathering volumes (TBtu)		296.9			300.1			292.5			291.9			1,181.4			269.3
Gathering rate ($/MMBtu)	$	0.2590		$	0.2634		$	0.2708		$	0.2730		$	0.2664		$	0.2792

Processing volumes (TBtu)		191.8			204.8			210.0			226.5			833.1			226.9
Processing rate ($/MMBtu)	$	0.1298		$	0.1340		$	0.1314		$	0.1289		$	0.1310		$	0.1269

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

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


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

Power
(UNAUDITED)


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

Revenues:
Natural gas & power	$	2,053.3		$	1,606.6		$	2,104.1		$	1,698.1		$	7,462.1		$	1,775.2
Other		(0.1	)		0.4			—			—			0.3			(0.1	)

Total revenues		2,053.2			1,607.0			2,104.1			1,698.1		$	7,462.4			1,775.1

Segment costs and expenses:
Costs and operating expenses		2,082.1			1,671.4			2,167.6			1,716.8			7,637.9			1,837.7
Selling, general and administrative expenses		(4.5	)		18.9			22.2			25.6			62.2			18.9
Other income — net		(2.1	)		(3.4	)		(8.4	)		—			(13.9	)		(0.4	)

Total segment costs and expenses		2,075.5			1,686.9			2,181.4			1,742.4			7,686.2			1,856.2

Equity Earnings		(0.2	)		0.3			7.6			5.3			13.0			—


Reported segment loss		(22.5	)		(79.6	)		(69.7	)		(39.0	)		(210.8	)		(81.1	)

Nonrecurring adjustments		—			—			(9.2	)		1.3			(7.9	)		—


Recurring segment loss, pre-tax	$	(22.5	)	$	(79.6	)	$	(78.9	)	$	(37.7	)	$	(218.7	)	$	(81.1	)

Operating statistics

Volumes
Natural gas (Bcfd)
Sales to third parties		1.7			1.5			1.7			1.7			1.7			1.9
Sales to other segments		0.4			0.4			0.4			0.4			0.4			0.4
For use in tolling agreements and by owned generation		0.1			0.2			0.4			0.1			0.2			0.1

Total managed		2.2			2.1			2.5			2.2			2.3			2.4

Power (GWh)		11,505			12,949			17,430			11,982			53,866			10,353

Additional statistics

Value at risk


	Quarter ended 3/31/2007
	(in Millions)
One day VaR - 95% confidence level
Trading	$	2.2
Non-Trading	$	13.1
Aggregate Earnings VaR	$	10.1

Net Credit Exposure


	Investment
(in Millions)	Grade		Total
Gas and electric utilities	$	146.3	$	147.0
Energy marketers and traders		159.2		404.0
Financial institutions		197.6		197.6
Other		1.3		1.3

	$	504.4	$	749.9

Credit Reserves				(15.9	)

Net Credit Exposure from Derivative Contracts			$	734.0

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	$	14.4
13-36 months		0.9
37-60 months		(1.1	)
61-120 months		(1.4	)
121+ months		0.1

Total Fair Value		12.9

Non-Trading MTM Derivatives and SFAS 133 Hedges		361.8
Non-Power Business Unit Hedges		13.7

Total Net Derivative Assets and Liabilities	$	388.4


Power Portfolio	Quarter Ended
(Megawatts)	3/31/07
Owned		207
Contracted		9,708

Total		9,915

Credit Support (in Millions)


As of March 31, 2007
Prepays	$	4
Margins	$	(107	)
Adequate Assurance	$	4

Capital Expenditures and Investments
(UNAUDITED)


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

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

Gas Pipe line:
Northwest Pipe line		40.3			96.0		177.4			159.1		472.8			49.3
Transcontinental Gas Pipe Line		46.4			106.7		109.4			75.6		338.1			59.0
Other		—			—		—			—		—			—

Total		86.7			202.7		286.8			234.7		810.9			108.3

Midstream Gas & Liquids		70.7			39.3		83.5			63.5		257.0			54.8
Power		0.6			0.6		(0.1	)		0.1		1.2			—
Other		—			7.8		1.2			9.1		18.1			3.5

Total	$	468.3		$	534.3	$	756.3		$	750.3	$	2,509.2		$	509.1


Purchase of investments:
Gas Pipe line		—			—		4.5			0.7		5.2			1.1
Midstream Gas & Liquids		(3.4	)		0.8		—			2.4		(0.2	)		—
Other		13.1			26.0		4.6			0.2		43.9			20.1

Total	$	9.7		$	26.8	$	9.1		$	3.3	$	48.9		$	21.2


Summary:
Exploration & Production	$	310.3		$	283.9	$	384.9		$	442.9	$	1,422.0		$	342.5
Gas Pipe line		86.7			202.7		291.3			235.4		816.1			109.4
Midstream Gas& Liquids		67.3			40.1		83.5			65.9		256.8			54.8
Power		0.6			0.6		(0.1	)		0.1		1.2			—
Other		13.1			33.8		5.8			9.3		62.0			23.6

Total	$	478.0		$	561.1	$	765.4		$	753.6	$	2,558.1		$	530.3


Cumulative summary:
Exploration & Production	$	310.3		$	594.2	$	979.1		$	1,422.0	$	1,422.0		$	342.5
Gas Pipe line		86.7			289.4		580.7			816.1		816.1			109.4
Midstream Gas & Liquids		67.3			107.4		190.9			256.8		256.8			54.8
Power		0.6			1.2		1.1			1.2		1.2			—
Other		13.1			46.9		52.7			62.0		62.0			23.6

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

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


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

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

Total		68.5			70.5			70.3			72.4			281.7			77.3
Midstream Gas & Liquids		49.4			49.9			49.9			52.0			201.2			52.8
Power		3.2			3.2			2.3			2.0			10.7			1.8
Other		2.9			2.7			3.1			3.0			11.7			2.7

Total	$	197.0		$	210.5		$	220.4		$	237.6		$	865.5		$	248.2


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

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

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

Non-GAAP Utility Statement:

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

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

Adjustment to remove MTM effect

Dollars in millions except for per share amounts


	2007							2006
	1Q		2Q	3Q	4Q	Year		1Q			2Q		3Q		4Q		Year
Recurring income from cont. ops available to common shareholders	$	128				$	128	$	136		$	113	$	113	$	158	$	520
Recurring diluted earnings per common share	$	0.21				$	0.21	$	0.23		$	0.19	$	0.19	$	0.26	$	0.86

Mark-to-Market (MTM) adjustments:
Reverse forward unrealized MTM (gains)/losses		71					71		(43	)		38		16		11		22
Add realized gains from MTM previously recognized		8					8		77			100		80		25		282

Total MTM adjustments		79					79		34			138		96		36		304

Tax effect of total MTM adjustments (at 39%)		31					31		13			53		37		14		116


After tax MTM adjustments		48					48		21			85		59		22		188

Recurring income from cont. ops available to common shareholders after MTM adjust.	$	176				$	176	$	157		$	198	$	172	$	180	$	708
Recurring diluted earnings per share after MTM adj.	$	0.29				$	0.29	$	0.26		$	0.33	$	0.28	$	0.30	$	1.17

weighted average shares — diluted (thousands)		611,470					611,470		607,073			595,561		609,062		610,352		608,627

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

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

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


	2006																2007
(Dollars in millions, except per-share amounts)	1st Qtr				2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr
Income (loss) from continuing operations available to common stockholders	$	131.1		(	$	63.9	)	$	110.1		$	155.5		$	332.8		$	131.8


Income (loss) from continuing operations — diluted earnings (loss) per common share	$	0.22		(	$	0.11	)	$	0.19		$	0.25		$	0.55		$	0.22


Nonrecurring items:

Gas Pipeline
Reversal of litigation contigency due to favorable ruling — TGPL		(2.0	)			—			—			—			(2.0	)		—

Total Gas Pipeline nonrecurring items		(2.0	)			—			—			—			(2.0	)		—

Midstream Gas & Liquids
Reversal of a maintenance accrual		—				—			—			—			—			(7.9	)
Gains on sales of MGL properties		—				—			(7.9	)		—			(7.9	)		—
Adjustment of accounts payable accrual		—				—			10.6			—			10.6			—
Losses on asset retirements 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	) ⁽¹⁾			—			—			—			(6.3	)		—

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

Power
Reduction of contingent obligations associated with our former distributive power generation business		—				—			(12.7	)		—			(12.7	)		—
Accrual for litigation contingencies ⁽¹⁾		—				—			3.5			1.3			4.8			—

Total Power nonrecurring items		—				—			(9.2	)		1.3			(7.9	)		—

Nonrecurring items included in segment profit (loss)		(8.3	)			68.0			1.1			3.6			64.4			(7.9	)
Nonrecurring items below segment profit (loss)
Impairment of cost-based investment — Petrowayu (Investing income / loss — Exploration & Production)		—				—			—			16.4			16.4			—
Securities litigation settlement and related costs ⁽¹⁾		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			1.4

		16.5				185.1			4.0			19.8			225.4			1.4
Total nonrecurring items		8.2				253.1			5.1			23.4			289.8			(6.5	)
Tax effect for above items ⁽¹⁾		3.4				76.6			1.8			2.8			84.6			(2.5	)
Adjustment for nonrecurring excess deferred tax provision		—				—			—			7.4			7.4			—
Adjustment for tax benefit related to federal income tax litigation		—				—			—			(25.1	)		(25.1	)		—

Recurring income from continuing operations available to common stockholders	$	135.9			$	112.6		$	113.4		$	158.4		$	520.3		$	127.8

Recurring diluted earnings per common share	$	0.23			$	0.19		$	0.19		$	0.26		$	0.86		$	0.21

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


⁽¹⁾		The tax rate applied to Midstream’s international contract dispute settlement in 1st quarter 2006 is 34%. The tax rate applied to nonrecurring items for 2nd quarter 2006 has been adjusted for the effect of 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.

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