UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2007

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

THE WILLIAMS COMPANIES, INC.

(Exact name of registrant as specified in its charter)

DELAWARE		73-0569878
(State of Incorporation)		(IRS Employer Identification Number)
ONE WILLIAMS CENTER, TULSA, OKLAHOMA		74172
(Address of principal executive office)		(Zip Code)

Registrant’s telephone number: (918) 573-2000

NO CHANGE Former name, former address and former fiscal year, if changed since last report.

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ   No o

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.)

Yes o   No þ

     Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.

Class		Outstanding at July 31, 2007
Common Stock, $1 par value		600,232,917 Shares

 

 

The Williams Companies, Inc.

Index

		Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Operations — Three and Six Months Ended June 30, 2007 and 2006			3
Consolidated Balance Sheet — June 30, 2007 and December 31, 2006			4
Consolidated Statement of Cash Flows — Six Months Ended June 30, 2007 and 2006			5
Notes to Consolidated Financial Statements			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			26
Item 3. Quantitative and Qualitative Disclosures about Market Risk			49
Item 4. Controls and Procedures			51
Part II. Other Information			52
Item 1. Legal Proceedings			52
Item 1A. Risk Factors			52
Item 4. Submission of Matters to a Vote of Security Holders			52
Item 5. Other Information			52
Item 6. Exhibits			53
Summary of the Non-Management Director Compensation Action
Computation of Ratio of Earnings to Fixed Charges
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO and CFO Pursuant to Section 906

     Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

     All statements, other than statements of historical facts, included in this report which address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, statements regarding:

	•		Amounts and nature of future capital expenditures;
	•		Expansion and growth of our business and operations;
	•		Business strategy;
	•		Estimates of proved gas and oil reserves;
	•		Reserve potential;
	•		Development drilling potential;
	•		Cash flow from operations;
	•		Seasonality of certain business segments;
	•		Power, natural gas and natural gas liquids prices and demand.

     Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this document. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

	•		Availability of supplies (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and increased costs of capital;
	•		Inflation, interest rates, fluctuation in foreign exchange, and general economic conditions;
	•		The strength and financial resources of our competitors;
	•		Development of alternative energy sources;
	•		The impact of operational and development hazards;
	•		Costs of, changes in, or the results of laws, government regulations including proposed climate change legislation, environmental liabilities, litigation, and rate proceedings;
	•		Changes in the current geopolitical situation;
	•		Risks related to strategy and financing, including restrictions stemming from our debt agreements and our lack of investment grade credit ratings;
	•		Risk associated with future weather conditions and acts of terrorism.

     Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

     In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

     Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item IA. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2006 and Part II, Item 1A. Risk Factors of this Form 10-Q.

The Williams Companies, Inc.
Consolidated Statement of Operations
(Unaudited)

		Three months								Six months
		ended June 30,								ended June 30,
(Dollars in millions, except per-share amounts)		2007				2006*				2007				2006*
Revenues:
Exploration & Production		$	539.5			$	342.3			$	1,022.2			$	698.3
Gas Pipeline			414.8				337.3				785.6				671.3
Midstream Gas & Liquids			1,234.3				1,043.5				2,229.7				2,022.9
Gas Marketing Services			1,393.4				1,116.8				2,681.7				2,540.9
Other			14.9				13.0				28.5				32.1
Intercompany eliminations			(773.5	)			(633.0	)			(1,556.0	)			(1,358.4	)
Total revenues			2,823.4				2,219.9				5,191.7				4,607.1
Segment costs and expenses:
Costs and operating expenses			2,180.2				1,776.8				4,023.5				3,738.8
Selling, general and administrative expenses			107.0				95.8				209.5				153.6
Other (income) expense — net			(12.0	)			65.9				(29.9	)			44.3
Total segment costs and expenses			2,275.2				1,938.5				4,203.1				3,936.7
General corporate expenses			36.2				33.7				75.6				64.3
Securities litigation settlement and related costs			—				160.7				—				161.9
Operating income (loss):
Exploration & Production			204.5				113.9				387.3				256.5
Gas Pipeline			165.0				112.5				305.4				239.7
Midstream Gas & Liquids			240.9				124.5				388.3				266.1
Gas Marketing Services			(63.5	)			(65.6	)			(93.3	)			(88.7	)
Other			1.3				(3.9	)			.9				(3.2	)
General corporate expenses			(36.2	)			(33.7	)			(75.6	)			(64.3	)
Securities litigation settlement and related costs			—				(160.7	)			—				(161.9	)
Total operating income			512.0				87.0				913.0				444.2
Interest accrued			(172.1	)			(179.9	)			(344.1	)			(341.2	)
Interest capitalized			6.7				4.0				11.6				7.0
Investing income			65.5				39.1				117.9				86.8
Early debt retirement costs			—				(4.4	)			—				(31.4	)
Minority interest in income of consolidated subsidiaries			(25.4	)			(8.3	)			(39.4	)			(15.4	)
Other income — net			9.3				8.0				11.3				16.1
Income (loss) from continuing operations before income taxes			396.0				(54.5	)			670.3				166.1
Provision for income taxes			152.1				4.3				256.7				92.7
Income (loss) from continuing operations			243.9				(58.8	)			413.6				73.4
Income (loss) from discontinued operations			189.2				(17.2	)			153.5				(17.5	)
Net income (loss)		$	433.1			$	(76.0	)		$	567.1			$	55.9
Basic earnings (loss) per common share:
Income (loss) from continuing operations		$	.40			$	(.10	)		$	.69			$	.12
Income (loss) from discontinued operations			.32				(.03	)			.26				(.03	)
Net income (loss)		$	.72			$	(.13	)		$	.95			$	.09
Weighted-average shares (thousands)			599,518				595,561				598,778				593,495
Diluted earnings (loss) per common share:
Income (loss) from continuing operations		$	.40			$	(.10	)		$	.68			$	.12
Income (loss) from discontinued operations			.31				(.03	)			.25				(.03	)
Net income (loss)		$	.71			$	(.13	)		$	.93			$	.09
Weighted-average shares (thousands)			613,172				595,561				612,325				598,634
Cash dividends declared per common share		$	.10			$	.09			$	.19			$	.165

See accompanying notes.

The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)

		June 30,				December 31,
(Dollars in millions, except per-share amounts)		2007				2006*
ASSETS
Current assets:
Cash and cash equivalents		$	1,739.0			$	2,268.6
Restricted cash			94.8				91.6
Accounts and notes receivable (net of allowance of $15.1 in 2007 and $14.8 in 2006)			1,030.6				980.8
Inventories			223.5				237.6
Derivative assets			1,000.2				1,285.5
Margin deposits			120.6				59.3
Assets of discontinued operations			2,255.4				837.3
Deferred income taxes			363.8				337.2
Other current assets and deferred charges			380.1				224.1
Total current assets			7,208.0				6,322.0
Restricted cash			34.4				34.5
Investments			860.7				866.0
Property, plant and equipment — net			14,928.1				14,157.4
Derivative assets			1,326.7				1,844.0
Goodwill			1,011.4				1,011.4
Assets of discontinued operations			—				564.7
Other assets and deferred charges			676.8				602.4
Total assets		$	26,046.1			$	25,402.4
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	1,038.6			$	906.4
Accrued liabilities			1,189.9				1,223.5
Customer margin deposits payable			208.5				128.7
Derivative liabilities			1,061.1				1,303.6
Liabilities of discontinued operations			1,697.2				739.3
Long-term debt due within one year			468.1				392.1
Total current liabilities			5,663.4				4,693.6
Long-term debt			7,443.2				7,622.0
Deferred income taxes			3,083.8				2,879.9
Derivative liabilities			1,489.0				1,920.2
Liabilities of discontinued operations			—				146.5
Other liabilities and deferred income			857.7				986.2
Contingent liabilities and commitments (Note 11)
Minority interests in consolidated subsidiaries			1,085.7				1,080.8
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 605.4 million shares issued at June 30, 2007 and 602.8 million shares issued at December 31, 2006)			605.4				602.8
Capital in excess of par value			6,679.1				6,605.7
Accumulated deficit			(598.0	)			(1,034.0	)
Accumulated other comprehensive loss			(222.0	)			(60.1	)
			6,464.5				6,114.4
Less treasury stock, at cost (5.7 million shares of common stock in 2007 and 2006)			(41.2	)			(41.2	)
Total stockholders’ equity			6,423.3				6,073.2
Total liabilities and stockholders’ equity		$	26,046.1			$	25,402.4

See accompanying notes.

The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)

		Six months ended June 30,
(Dollars in millions)		2007				2006*
OPERATING ACTIVITIES:
Net income		$	567.1			$	55.9
Adjustments to reconcile to net cash provided by operations:
Reclassification of deferred net hedge gains related to sale of power business			(429.3	)			—
Depreciation, depletion and amortization			517.0				407.5
Accrual for securities litigation settlement and related costs			—				161.9
Provision for deferred income taxes			330.7				40.6
Provision for loss on investments, property and other assets			132.6				4.0
Net gain on disposition of assets			(17.6	)			(9.8	)
Early debt retirement costs			—				31.4
Minority interest in income of consolidated subsidiaries			39.4				15.4
Amortization of stock-based awards			32.7				21.4
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable			(156.9	)			440.7
Inventories			10.4				(35.0	)
Margin deposits and customer margin deposits payable			18.5				(212.7	)
Other current assets and deferred charges			(11.9	)			(61.0	)
Accounts payable			42.0				(300.7	)
Accrued liabilities			(123.9	)			(49.4	)
Changes in current and noncurrent derivative assets and liabilities			139.7				158.8
Other, including changes in noncurrent assets and liabilities			(106.3	)			4.3
Net cash provided by operating activities			984.2				673.3
FINANCING ACTIVITIES:
Proceeds from long-term debt			184.4				699.4
Payments of long-term debt			(296.7	)			(728.2	)
Proceeds from issuance of common stock			28.8				15.0
Proceeds from sale of limited partner units of consolidated partnership			—				225.2
Tax benefit of stock-based awards			15.7				5.2
Payments for debt issuance costs and amendment fees			(2.1	)			(26.9	)
Premiums paid on early debt retirement			(7.1	)			(25.8	)
Dividends paid			(114.3	)			(98.2	)
Dividends and distributions paid to minority interests			(37.3	)			(16.8	)
Changes in restricted cash			(3.2	)			7.1
Changes in cash overdrafts			22.0				(63.4	)
Other — net			2.8				(1.1	)
Net cash used by financing activities			(207.0	)			(8.5	)
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures			(1,226.6	)			(1,002.6	)
Changes in accounts payable and accrued liabilities			46.4				—
Net proceeds from dispositions			(9.7	)			3.7
Proceeds from contract termination payment			—				3.3
Purchases of investments/advances to affiliates			(24.1	)			(36.5	)
Purchases of auction rate securities			(249.7	)			(327.3	)
Proceeds from sales of auction rate securities			104.9				21.8
Proceeds from dispositions of investments and other assets			46.3				51.3
Other — net			5.7				4.7
Net cash used by investing activities			(1,306.8	)			(1,281.6	)
Decrease in cash and cash equivalents			(529.6	)			(616.8	)
Cash and cash equivalents at beginning of period			2,268.6				1,597.2
Cash and cash equivalents at end of period		$	1,739.0			$	980.4

*Revised as discussed in Note 2.

See accompanying notes.

The Williams Companies, Inc.
Notes to Consolidated Financial Statements
(Unaudited)

Note 1. General

     Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto in our Annual Report on Form 10-K. The accompanying unaudited financial statements include all normal recurring adjustments that, in the opinion of our management, are necessary to present fairly our financial position at June 30, 2007, and results of operations for the three and six months ended June 30, 2007 and 2006 and cash flows for the six months ended June 30, 2007 and 2006.

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Note 2. Basis of Presentation

     In accordance with the provisions related to discontinued operations within Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the accompanying consolidated financial statements and notes reflect the results of operations and financial position of our power business as discontinued operations. (See Note 3.) These operations, which were part of our previously reported Power segment, include:

	•		Our 7,500-megawatt portfolio of power-related contracts being sold to Bear Energy, LP, a unit of the Bear Stearns Company, Inc. This includes tolling contracts, full requirements contracts, tolling resales, heat rate options, related hedges and other related assets including certain property and software.
	•		Our natural gas-fired electric generating plant located in Hazleton, Pennsylvania (Hazleton).

     We have restated all segment information in the Notes to Consolidated Financial Statements for the prior periods presented to reflect the discontinued operations noted above. This restatement reflects the creation of a new Gas Marketing Services segment, which includes certain continued marketing and risk management operations that support our natural gas businesses. These operations were part of our previously reported Power segment but will now be managed and reported as a separate segment.

     Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.

     Cash flows are presented without separate disclosure of discontinued operations. Amounts reported for the prior period have been revised with no material impact. This revision did not change the total reported net cash provided or used by operating, financing, or investing activities.

     We currently own approximately 22.5 percent of Williams Partners L.P., including the interests of the general partner, which is wholly owned by us. Williams Partners L.P. is consolidated within our Midstream Gas & Liquids (Midstream) segment in accordance with Emerging Issues Task Force (EITF) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.”

Note 3. Discontinued Operations

     On May 21, 2007, we announced a definitive agreement to sell substantially all of our power business to Bear Energy, LP, a unit of the Bear Stearns Company, Inc. for $512 million. Under the agreement, this amount will be reduced by expected net portfolio cash flows from an April 1, 2007, valuation date through the transaction closing date. Mark-to-market gains and losses between this valuation date and the close of the transaction will not impact the economic value of the sale, although they may change the recorded gain or loss on the sale as derivative assets and liabilities included in the transaction continue to be valued at fair value.

Notes (Continued)

     In addition, we expect to sell certain remaining power assets later this year. We have retained the exposure related to contingent liabilities associated with our power business. (See Note 11.) The following table outlines the impact to our previously reported Power segment.

	Previous Power Segment Component			New Presentation
	Portfolio of power-related contracts, including full requirements contracts, tolling resales, heat rate options, related hedges and other related assets including certain property and software			Being sold to Bear Energy, LP and reported as discontinued operations
	Natural gas-fired electric generating plant near Hazleton, Pennsylvania			Being marketed for sale and reported as discontinued operations
	Marketing and risk management operations associated with managing our natural gas businesses			Retained and reported within the new Gas Marketing Services segment
	Equity investment in Aux Sable Liquid Products, LP (Aux Sable)			Retained and reported within the Midstream segment
	Natural gas-fired electric generating plant near Bloomfield, New Mexico (Milagro facility)			Reported within the Other segment, as we continue to evaluate whether to retain or sell

Summarized results of discontinued operations

     The following table presents the summarized results of discontinued operations for the three and six months ended June 30, 2007 and June 30, 2006.

		Three months ended								Six months ended
		June 30,								June 30,
		2007				2006				2007				2006
		(Millions)								(Millions)
Revenues		$	1,023.1			$	495.2			$	1,506.9			$	1,135.5
Income (loss) from discontinued operations before income taxes			433.1				(28.1	)			375.8				(28.0	)
Impairments			(125.9	)			—				(125.9	)			—
Benefit (provision) for income taxes			(118.0	)			10.9				(96.4	)			10.5
Income (loss) from discontinued operations		$	189.2			$	(17.2	)		$	153.5			$	(17.5	)

     Income (loss) from discontinued operations before income taxes for the three and six months ended June 30, 2007, includes a gain of $429.3 million (reported in revenues of discontinued operations) associated with the reclassification of deferred net hedge gains from accumulated other comprehensive income to earnings. This reclassification was based on the determination that the forecasted transactions related to the derivative cash flow hedges being sold were no longer probable of occurring. (See Note 12.) The three and six months ended June 30, 2007, include unrealized mark-to-market gains and (losses) of approximately $4 million and ($23) million, respectively. Second-quarter 2007 also includes approximately $12 million of sale-related expenses.

     Income (loss) from discontinued operations before income taxes for the three and six months ended June 30, 2006 includes a $19.2 million charge for an adverse arbitration award related to our former chemical fertilizer business.

     The impairments for the three and six months ended June 30, 2007, include approximately $111 million related to the carrying value of certain derivative contracts for which we had previously elected the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and, accordingly, were no longer recording at fair value and approximately $15 million related to our Hazleton facility. These impairments are based on our comparison of the carrying value to the estimated fair value less cost to sell.

     We expect that our income from discontinued operations for the six months ended June 30, 2007, will be significantly reduced by an anticipated loss on sale to be recognized later this year upon closing of the transaction with Bear Energy, LP, and by additional transaction costs. Operating results through the date of close may also serve to reduce reported income from discontinued operations.

Notes (Continued)

Summarized assets and liabilities of discontinued operations

     The following table presents the summarized assets and liabilities of discontinued operations as of June 30, 2007 and December 31, 2006.

		June 30,				December 31,
		2007				2006
		(Millions)
Derivative assets		$	707.5			$	592.7
Other current assets			285.9				244.6
Total current assets			993.4				837.3
Property, plant and equipment — net			7.5				23.3
Derivative assets			1,254.1				541.0
Other noncurrent assets			.4				.4
Total noncurrent assets			1,262.0				564.7
Total assets		$	2,255.4			$	1,402.0
Reflected on balance sheet as:
Current assets		$	2,255.4			$	837.3
Noncurrent assets			—				564.7
Total assets		$	2,255.4			$	1,402.0
Derivative liabilities		$	606.5			$	479.3
Other current liabilities			239.7				260.0
Total current liabilities			846.2				739.3
Derivative liabilities			839.0				123.7
Other noncurrent liabilities			12.0				22.8
Total noncurrent liabilities			851.0				146.5
Total liabilities		$	1,697.2			$	885.8
Reflected on balance sheet as:
Current liabilities		$	1,697.2			$	739.3
Noncurrent liabilities			—				146.5
Total liabilities		$	1,697.2			$	885.8

Note 4. Other Accruals

     Significant gains or losses from other accruals or adjustments reflected in other (income) expense — net within segment costs and expenses are as follows:

		Three months ended								Six months ended
		June 30,								June 30,
		2007				2006				2007				2006
		(Millions)								(Millions)
Gas Pipeline
Change in estimate related to a regulatory liability		$	(16.6	)		$	—			$	(16.6	)		$	—
Midstream
Accrual for Gulf Liquids litigation contingency. Associated with this contingency is an interest accrual of $25 million, which is included in interest accrued (See Note 11)			—				68.0				—				68.0

     Investing income within our Other segment for the three and six months ended June 30, 2007, includes $13.9 million and $14.4 million, respectively, of gains from the sales of cost-based investments.

Notes (Continued)

Note 5. Provision for Income Taxes

     The provision for income taxes includes:

		Three months ended								Six months ended
		June 30,								June 30,
		2007				2006				2007				2006
		(Millions)								(Millions)
Current:
Federal		$	(5.8	)		$	9.6			$	(3.0	)		$	12.7
State			3.3				9.1				.9				11.7
Foreign			15.3				9.2				24.6				17.2
			12.8				27.9				22.5				41.6
Deferred:
Federal			124.8				(20.7	)			201.0				35.8
State			9.4				(8.0	)			22.1				4.6
Foreign			5.1				5.1				11.1				10.7
			139.3				(23.6	)			234.2				51.1
Total provision		$	152.1			$	4.3			$	256.7			$	92.7

     The effective income tax rate for the three and six months ended June 30, 2007, is greater than the federal statutory rate due primarily to the effect of state income taxes and net foreign operations. The higher effective tax rate was partially offset by a benefit recognized in association with a favorable private letter ruling received from the Internal Revenue Service (IRS) concerning our securities litigation settlement and fees, a portion of which were previously treated as nondeductible.

     We have a tax provision on a pre-tax loss for the three months ended June 30, 2006, due primarily to the effect of net foreign operations, estimated nondeductible expenses associated with our securities litigation settlement and fees, and nondeductible expenses associated with the first quarter 2006 conversion of convertible debentures. The effective income tax rate for the six months ended June 30, 2006, is greater than the federal statutory rate due primarily to these factors and the effect of state income taxes.

     Effective January 1, 2007, we adopted Financial Accounting Standards Board (FASB) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48) and, as required by the Interpretation, recognized the net impact of the cumulative effect of adoption as a $16.8 million decrease to retained earnings. The Interpretation prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, the enterprise determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. A tax position that meets the more likely than not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured as the largest amount of benefit, determined on a cumulative probability basis, that is greater than 50 percent likely of being realized upon ultimate settlement.

     As of January 1, 2007, we had approximately $93 million of unrecognized tax benefits. If recognized, approximately $83 million, net of federal tax expense, would be recorded as a reduction of income tax expense. There have been no significant changes to these amounts as of June 30, 2007.

     We recognize related interest and penalties as a component of income tax expense. Approximately $97 million of interest and $5 million of penalties have been accrued at January 1, 2007. Of the $97 million interest accrued, approximately $22 million relates to uncertain tax positions.

     As of January 1, 2007, the IRS examination of Williams’ consolidated U.S. income tax return for 2002 was in process. During the first quarter of 2007, the IRS also commenced examination of the 2003 through 2005 consolidated U.S. income tax returns. IRS examinations for 1996 through 2001 have been completed but the years remain open while certain issues are under review with the Appeals Division of the IRS. The statute of limitations for most states expires one year after IRS audit settlement.

     Generally, tax returns for our Venezuelan and Canadian entities are open to audit from 2002 through 2006. Tax returns for our Argentine entities are open to audit from 2001 through 2006. Certain Canadian entities are currently under examination.

Notes (Continued)

Note 6. Earnings (Loss) Per Common Share from Continuing Operations

     Basic and diluted earnings (loss) per common share are computed as follows:

		Three months ended								Six months ended
		June 30,								June 30,
		2007				2006				2007				2006
		(Dollars in millions, except per-share amounts;
		shares in thousands)
Income (loss) from continuing operations available to common stockholders for basic and diluted earnings per share (1)		$	243.9			$	(58.8	)		$	413.6			$	73.4
Basic weighted-average shares			599,518				595,561				598,778				593,495
Effect of dilutive securities:
Unvested restricted stock units (2)			1,522				—				1,443				865
Stock options			4,810				—				4,780				4,274
Convertible debentures (3)			7,322				—				7,324				—
Diluted weighted-average shares			613,172				595,561				612,325				598,634
Earnings (loss) per share from continuing operations:
Basic		$	.40			$	(.10	)		$	.69			$	.12
Diluted		$	.40			$	(.10	)		$	.68			$	.12

     Approximately 7.3 million and 8.9 million weighted-average shares related to the assumed conversion of convertible debentures, as well as the related interest, have been excluded from the computation of diluted earnings per common share for the three and six months ended June 30, 2006, respectively. Inclusion of these shares would have an anti-dilutive effect on the diluted earnings per common share. We estimate that if income (loss) from continuing operations available to common stockholders was increased to $55.6 million and $112.3 million for the three and six months ended June 30, 2006, respectively, then these shares would become dilutive.

     The table below includes information related to stock options that were outstanding at June 30 of each respective year but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the second quarter weighted-average market price of our common shares.

		June 30,				June 30,
		2007				2006
Options excluded (millions)			2.2				4.3
Weighted-average exercise prices of options excluded		$	37.21			$	35.29
Exercise price ranges of options excluded		$	31.55-$42.29			$	22.12-$42.29
Second quarter weighted-average market price		$	30.07			$	21.96

     In the second quarter of 2006, an additional 4.3 million options with exercise prices less than the second quarter weighted-average market price have been excluded from the computation of weighted-average stock options due to the shares being anti-dilutive.

Notes (Continued)

Note 7. Employee Benefit Plans

     Net periodic pension expense and other postretirement benefit expense for the three and six months ended June 30, 2007 and 2006 are as follows. We do not expect that the sale of our power business will have a significant impact on our employee benefit plans. (See Note 3.)

		Pension Benefits
		Three months								Six months
		ended June 30,								ended June 30,
		2007				2006				2007				2006
		(Millions)								(Millions)
Components of net periodic pension expense:
Service cost		$	5.8			$	5.4			$	11.6			$	11.1
Interest cost			13.8				13.1				26.9				24.9
Expected return on plan assets			(18.4	)			(16.5	)			(36.3	)			(33.4	)
Amortization of prior service credit			(.1	)			(.2	)			(.2	)			(.3	)
Amortization of net actuarial loss			5.2				5.7				9.3				9.5
Regulatory asset amortization (deferral)			.3				—				.3				(.1	)
Net periodic pension expense		$	6.6			$	7.5			$	11.6			$	11.7

		Other Postretirement Benefits
		Three months								Six months
		ended June 30,								ended June 30,
		2007				2006				2007				2006
		(Millions)								(Millions)
Components of net periodic other postretirement benefit expense:
Service cost		$	.7			$	.7			$	1.5			$	1.6
Interest cost			4.1				3.4				8.5				8.6
Expected return on plan assets			(3.1	)			(2.7	)			(6.1	)			(5.6	)
Amortization of prior service credit			(.1	)			(.1	)			(.2	)			(.2	)
Amortization of net actuarial gain			—				(.9	)			—				—
Regulatory asset amortization			1.3				2.0				2.6				3.6
Net periodic other postretirement benefit expense		$	2.9			$	2.4			$	6.3			$	8.0

     During the six months ending June 30, 2007, we have contributed $20.7 million to our pension plans and $7.1 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $20 million to our pension plans in 2007 for a total of approximately $41 million. We presently anticipate making additional contributions of approximately $7 million to our other postretirement benefit plans in 2007 for a total of approximately $14 million.

Note 8. Stock-Based Compensation

     Effective May 17, 2007, our stockholders approved a new plan that will provide common-stock-based awards going forward to both employees and nonmanagement directors. The new plan generally contains terms and provisions consistent with the previous plans. The new plan reserves 19 million shares for issuance. Awards outstanding in all prior plans remain in those plans with their respective terms and provisions. No new grants will be made from the prior plans. The new plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. Restricted stock units are generally valued at market value on the grant date of the award and generally vest over three years. The purchase price per share for stock options generally may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of the grant and can be subject to accelerated vesting if certain future stock prices or if specific financial performance targets are achieved. Stock options generally expire 10 years after grant. At June 30, 2007, 39.7 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 18.9 million shares were available for future grants.

     Additionally, on May 17, 2007, our stockholders approved a newly proposed Employee Stock Purchase Plan (ESPP) which authorizes up to 2 million shares of our common stock to be available for sale under the plan. The ESPP enables eligible participants to purchase our common stock through payroll deductions not exceeding an annual amount of $15,000 per participant. The ESPP provides for offering periods during which shares may be purchased and continues until the earliest of: (1) the Board of Directors terminates the ESPP, (2) the sale of all shares available under the ESPP, or (3) the tenth anniversary of the date the Plan was approved by the stockholders. The first offering under the ESPP will commence on October 1, 2007 and end on December 31, 2007. Subsequent offering periods will be from January through June and from July through December. Generally, all employees are

Notes (Continued)

eligible to participate in the ESPP, with the exception of executives and international employees. The number of shares eligible for an employee to purchase during each offering period is limited to 750 shares. The purchase price of the stock is 85 percent of the lower of either the price on the first or the last day of the offering period. The ESPP requires a one-year holding period before the stock can be sold.

Note 9. Inventories

     Inventories at June 30, 2007 and December 31, 2006 are:

		June 30,				December 31,
		2007				2006
		(Millions)
Materials, supplies and other		$	96.4			$	82.1
Natural gas liquids			71.8				77.9
Natural gas in underground storage			55.3				77.6
		$	223.5			$	237.6

Note 10. Debt and Banking Arrangements

Long-Term Debt

Revolving credit and letter of credit facilities (credit facilities)

     At June 30, 2007, no loans are outstanding under our credit facilities. Letters of credit issued under our facilities are:

		Letters of Credit at
		June 30, 2007
		(Millions)
$500 million unsecured credit facilities		$	347.7
$700 million unsecured credit facilities		$	518.4
$1.5 billion unsecured credit facility		$	28.0

     On May 9, 2007, we amended our $1.5 billion unsecured credit facility, extending the maturity date from May 1, 2009 to May 1, 2012. Applicable borrowing rates and commitment fees for investment grade credit ratings were also modified.

Exploration & Production’s credit agreement

     In February 2007, Exploration & Production entered into a five-year unsecured credit agreement with certain banks in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. Under the credit agreement, Exploration & Production is not required to post collateral as long as the value of its domestic natural gas reserves, as determined under the provisions of the agreement, exceeds by a specified amount certain of its obligations including any outstanding debt and the aggregate out-of-the-money positions on hedges entered into under the credit agreement. Exploration & Production is subject to additional covenants under the credit agreement including restrictions on hedge limits, the creation of liens, the incurrence of debt, the sale of assets and properties, and making certain payments, such as dividends, under certain circumstances.

Issuances and retirements

     On April 4, 2007, Northwest Pipeline retired $175 million of 8.125 percent senior unsecured notes due 2010. Northwest Pipeline paid premiums of approximately $7.1 million in conjunction with the early debt retirement. These premiums are considered recoverable through rates and are therefore deferred as a component of other assets and deferred charges on our consolidated balance sheet, amortizing over the life of the original debt.

     On April 5, 2007, Northwest Pipeline issued $185 million aggregate principal amount of 5.95 percent senior unsecured notes due 2017 to certain institutional investors in a private debt placement.

Notes (Continued)

Registration payment arrangements

     Under the terms of the Northwest Pipeline $185 million 5.95 percent senior unsecured notes mentioned above, Northwest Pipeline is obligated to file a registration statement for an offer to exchange the notes for a new issue of substantially identical notes to be registered under the Securities Act of 1933, as amended, within 180 days from closing and use its commercially reasonable efforts to cause the registration statement to be declared effective within 270 days after closing. Northwest Pipeline may be required to provide a shelf registration statement to cover resales of the notes under certain circumstances. Northwest Pipeline may also be required to pay additional interest, up to a maximum of 0.5 percent annually, if it fails to satisfy these obligations. Northwest Pipeline launched an exchange offer on July 26, 2007, which will expire on August 23, 2007, unless Northwest Pipeline chooses to extend the expiration.

     On June 20, 2006, Williams Partners L.P. issued $150 million aggregate principal amount of 7.5 percent senior unsecured notes in a private debt placement. On December 13, 2006, Williams Partners L.P. issued $600 million aggregate principal amount of 7.25 percent senior unsecured notes in a private debt placement. In connection with these issuances, Williams Partners L.P. entered into registration rights agreements with the initial purchasers of the senior unsecured notes. In these agreements they agreed to conduct a registered exchange offer for the senior unsecured notes or cause to become effective a shelf registration statement providing for resale of the senior unsecured notes. Williams Partners L.P. initiated exchange offers for both series on April 10, 2007. The exchange offers were completed and closed on May 11, 2007.

     On December 13, 2006, Williams Partners L.P. issued approximately $350 million of common and Class B units in a private equity offering. In connection with these issuances, Williams Partners L.P. entered into a registration rights agreement with the initial purchasers whereby Williams Partners L.P. agreed to file a shelf registration statement providing for the resale of the units. Additionally, the registration rights agreement provides for the registration of common units that would be issued upon conversion of the Class B units. On May 21, 2007, Williams Partners L.P.’s outstanding Class B units were converted into common units on a one-for-one basis. William Partners L.P. filed the shelf registration statement on January 12, 2007, and it became effective on March 13, 2007. If the shelf registration statement is unavailable for a period that exceeds an aggregate of 30 days in any 90-day period or 105 days in any 365-day period, the purchasers are entitled to receive liquidated damages. Liquidated damages are calculated as 0.25% of the Liquidated Damages Multiplier per 30-day period for the first 60 days following the 90th day, increasing by an additional 0.25% of the Liquidated Damages Multiplier per 30-day period for each subsequent 60 days, up to a maximum of 1.00% of the Liquidated Damages Multiplier per 30-day period. The Liquidated Damages Multiplier is (i) the product of $36.59 times the number of common units purchased plus (ii) the product of $35.81 times the number of Class B Units purchased.

     As of June 30, 2007, we have not accrued any liabilities for these registration payment arrangements.

Note 11. Contingent Liabilities and Commitments

Rate and Regulatory Matters and Related Litigation

     Our interstate pipeline subsidiaries have various regulatory proceedings pending. As a result, a portion of the revenues of these subsidiaries has been collected subject to refund. We have accrued a liability for these potential refunds as of June 30, 2007, which we believe is adequate for any refunds that may be required.

Issues Resulting from California Energy Crisis

     Our subsidiary, Williams Power Company, Inc. (WPC), whose results of operations were included in our previously reported Power segment (see Note 3), is engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the Federal Energy Regulatory Commission (FERC). These challenges included refund proceedings, summer 2002 90-day contracts, investigations of alleged market manipulation including withholding, gas indices and other gaming of the market, new long-term power sales to the State of California that were subsequently challenged and civil litigation relating to certain of these issues. We have entered into settlements with the State of California (State Settlement), major California utilities (Utilities Settlement), and others that substantially resolved each of these issues with these parties.

Notes (Continued)

     As a result of a December 19, 2006 Ninth Circuit Court of Appeals decision, certain contracts that WPC entered into during 2000 and 2001 may be subject to partial refunds. These contracts, under which WPC sold electricity, totaled approximately $89 million in revenue. While WPC is not a party to the cases involved in the appellate court decision, the buyer of electricity from WPC is a party to the cases and claims that WPC must refund to the buyer any loss it suffers due to the decision and the FERC’s reconsideration of the contract terms at issue in the decision.

     Certain other issues also remain open at the FERC and for other nonsettling parties.

Refund proceedings

     Although we entered into the State Settlement and Utilities Settlement, which resolved the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, such as various California end users that did not participate in the Utilities Settlement. As a part of the Utilities Settlement, we funded escrow accounts that we anticipate will satisfy any ultimate refund determinations in favor of the nonsettling parties. We are also owed interest from counterparties in the California market during the refund period for which we have recorded a receivable totaling approximately $24 million at June 30, 2007. Collection of the interest is subject to the conclusion of this proceeding. Therefore, we continue to participate in the FERC refund case and related proceedings. Challenges to virtually every aspect of the refund proceedings, including the refund period, were made to the Ninth Circuit Court of Appeals. On August 2, 2006, the Ninth Circuit issued its order that largely upheld the FERC’s prior rulings, but it expanded the types of transactions that were made subject to refund. Because of our settlement, we do not expect this decision will have a material impact on us. No final refund calculation, however, has been made, and certain aspects of the refund calculation process remain unclear and prevent that final refund calculation. As part of the State Settlement, an additional $45 million, previously accrued, remains to be paid to the California Attorney General (or his designee) over the next three years, with final payment of $15 million due on January 1, 2010.

Reporting of Natural Gas-Related Information to Trade Publications

     We disclosed on October 25, 2002, that certain of our natural gas traders had reported inaccurate information to a trade publication that published gas price indices. In 2002, we received a subpoena from a federal grand jury in northern California seeking documents related to our involvement in California markets, including our reporting to trade publications for both gas and power transactions. We have completed our response to the subpoena. Three former traders with WPC have pled guilty to manipulation of gas prices through misreporting to an industry trade periodical. One former trader has pled not guilty. In February 2006 we entered into a deferred prosecution agreement with the Department of Justice (DOJ) under which we paid $50 million. The agreement expired on May 21, 2007 and we expect no further action by the DOJ.

     Civil suits based on allegations of manipulating the gas indices have been brought against us and others, in each case seeking an unspecified amount of damages. We are currently a defendant in:

•

Class action litigation in federal court in Nevada alleging that we manipulated gas prices for direct purchasers of gas in California. We have settled this matter.

•

State court in California on behalf of certain individual gas users.

•

Class action litigation in state court in Colorado, Kansas, Missouri, Tennessee and Wisconsin brought on behalf of direct and indirect purchasers of gas in those states. The Tennessee purchasers have appealed the court’s February 2007 dismissal of the case before it. The cases in the other jurisdictions have been removed to federal court.

     It is reasonably possible that additional amounts may be necessary to resolve the remaining outstanding litigation in this area, the amount of which cannot be reasonably estimated at this time.

Mobile Bay Expansion

     In December 2002, an administrative law judge at the FERC issued an initial decision in Transcontinental Gas Pipe Line Corporation’s (Transco) 2001 general rate case which, among other things, rejected the recovery of the costs of Transco’s Mobile Bay expansion project from its shippers on a “rolled-in” basis and found that incremental

Notes (Continued)

pricing for the Mobile Bay expansion project is just and reasonable. In March 2004, the FERC issued an Order on Initial Decision in which it reversed certain parts of the administrative law judge’s decision and accepted Transco’s proposal for rolled-in rates. Gas Marketing Services holds long-term transportation capacity on the Mobile Bay expansion project. If the FERC had adopted the decision of the administrative law judge on the pricing of the Mobile Bay expansion project and also required that the decision be implemented effective September 1, 2001, Gas Marketing Services could have been subject to surcharges of approximately $124.3 million, including interest, through June 30, 2007, in addition to increased costs going forward. Certain parties have filed appeals in federal court seeking to have the FERC’s ruling on the rolled-in rates overturned.

Enron Bankruptcy

     We have outstanding claims against Enron Corp. and various of its subsidiaries (collectively “Enron”) related to its bankruptcy filed in December 2001. In 2002, we sold $100 million of our claims against Enron to a third party for $24.5 million. In 2003, Enron filed objections to these claims. We have resolved Enron’s objections, subject to court approval. Pursuant to the sales agreement, the purchaser of the claims demanded repayment of the purchase price for the reduced portions of the claims. In February 2007, we completed a settlement with the purchaser covering any potential repayment obligations.

Environmental Matters

Continuing operations

     Since 1989, our Transco subsidiary has had studies underway to test certain of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. Transco has responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of its sites. Transco has identified polychlorinated biphenyl (PCB) contamination in compressor systems, soils and related properties at certain compressor station sites. Transco has also been involved in negotiations with the EPA and state agencies to develop screening, sampling and cleanup programs. In addition, Transco commenced negotiations with certain environmental authorities and other programs concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. The costs of any such remediation will depend upon the scope of the remediation. At June 30, 2007, we had accrued liabilities of $5 million related to PCB contamination, potential mercury contamination, and other toxic and hazardous substances. Transco has been identified as a potentially responsible party at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, we have estimated our aggregate exposure for remediation of these sites to be less than $500,000, which is included in the environmental accrual discussed above.

     Beginning in the mid-1980’s, our Northwest Pipeline subsidiary evaluated many of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. Consistent with other natural gas transmission companies, Northwest Pipeline identified PCB contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, Northwest Pipeline identified hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the EPA in the late 1980s and Northwest Pipeline conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required Northwest Pipeline to reevaluate its previous mercury clean-ups in Washington. Consequently, Northwest Pipeline is conducting additional remediation activities at certain sites to comply with Washington’s current environmental standards. At June 30, 2007, we have accrued liabilities totaling approximately $8 million for these costs. We expect that these costs will be recoverable through Northwest Pipeline’s rates.

     We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At June 30, 2007, we have accrued liabilities totaling approximately $7 million for these costs.

     In August 2005, our subsidiary, Williams Production RMT Company, voluntarily disclosed two air permit violations to the Colorado Department of Public Health and Environment (CDPHE). To resolve the matter, we executed a Compliance Order on Consent (COC) with the CDPHE in May 2007 under which we paid a $180,000 penalty and are conducting a supplemental environmental project to upgrade our equipment.

Notes (Continued)

     In March 2006, the CDPHE issued a notice of violation (NOV) to Williams Production RMT Company related to our operating permit for the Rulison evaporation pond and water management facility. In August 2006, the CDPHE issued a NOV to Williams Production RMT Company related to our Grand Valley evaporation pond and water management facility located in Garfield County, Colorado, in which the CDPHE alleged that we failed to obtain a construction permit and to comply with certain provisions of our existing permit. On June 18, 2007, we received a combined COC from the CDPHE for both the Rulison and Grand Valley facilities proposing a penalty of $109,850 and including an option for a supplemental environmental project. We are evaluating the COC to determine our response.

     In July 2006, the CDPHE issued a NOV to Williams Production RMT Company related to operating permits for our Roan Cliffs and Hayburn gas plants in Garfield County, Colorado. We have met with the CDPHE to discuss the allegations contained in the NOV and have provided additional requested information to the agency.

     On April 11, 2007, the New Mexico Environment Department’s Air Quality Bureau issued a NOV to Williams Four Corners, LLC that alleged various emission and reporting violations in connection with our Lybrook gas processing plant’s flare and leak detection and repair program. We are investigating the matter.

     On April 16, 2007, the CDPHE issued a NOV to Williams Production RMT Company related to alleged air permit violations at the Rifle Station natural gas dehydration facility located in Garfield County, Colorado. The Rifle Station facility had been shut down prior to our receipt of the NOV and remains closed. We responded to the CDPHE’s notice on May 15, 2007.

     On April 27, 2007, the Wyoming Department of Environmental Quality (WDEQ) issued a NOV to Williams Production RMT Company that alleges violations of various Wyoming Pollution Discharge Elimination System permits in connection with our coal bed methane gas production facilities in the state. We are discussing the matter with the WDEQ.

     In July 2001, the EPA issued a request for information on oil releases and discharges in any amount from our pipelines, pipeline systems, and pipeline facilities used in the movement of oil or petroleum products, during the period from July 1, 1998 through July 2, 2001. In November 2001, we furnished our response. In March 2004, the DOJ invited the new owner of Williams Energy Partners and Magellan Midstream Partners, L.P. (Magellan) to enter into negotiations regarding alleged violations of the Clean Water Act. With the exception of four minor release events that underwent earlier cleanup operation under state enforcement actions, our environmental indemnification obligations to Magellan were released in a 2004 buyout. We do not expect further enforcement action with respect to the four release events or two 2006 spills at our Colorado and Wyoming facilities after providing additional requested information to the DOJ.

Former operations, including operations classified as discontinued

     In connection with the sale of certain assets and businesses, we have retained responsibility, through indemnification of the purchasers, for environmental and other liabilities existing at the time the sale was consummated, as described below.

     Agrico

     In connection with the 1987 sale of the assets of Agrico Chemical Company, we agreed to indemnify the purchaser for environmental cleanup costs resulting from certain conditions at specified locations to the extent such costs exceed a specified amount. At June 30, 2007, we have accrued liabilities of approximately $9 million for such excess costs.

     Other

     At June 30, 2007, we have accrued environmental liabilities totaling approximately $20 million related primarily to our:

•

Potential indemnification obligations to purchasers of our former retail petroleum and refining operations;

•

Former propane marketing operations, bio-energy facilities, petroleum products and natural gas pipelines;

Notes (Continued)

•

Discontinued petroleum refining facilities; and

•

Former exploration and production and mining operations.

     These costs include certain conditions at specified locations related primarily to soil and groundwater contamination and any penalty assessed on Williams Refining & Marketing, L.L.C. (Williams Refining) associated with noncompliance with the EPA’s National Emission Standards for Hazardous Air Pollutants (NESHAP). In 2002, Williams Refining submitted a self-disclosure letter to the EPA indicating noncompliance with those regulations. This unintentional noncompliance occurred due to a regulatory interpretation that resulted in under-counting the total annual benzene level at Williams Refining’s Memphis refinery. Also in 2002, the EPA conducted an all-media audit of the Memphis refinery. In 2006, we entered agreements totaling approximately $3 million that resolved both the government’s claims against us for alleged violations and an indemnity dispute with the purchaser in connection with our 2003 sale of the Memphis refinery. On May 1, 2007, the court approved our settlement with the government, and we paid the agreed settlement amount to the government on June 14, 2007. The matter is now concluded.

     In 2004, our Gulf Liquids subsidiary initiated a self-audit of all environmental conditions (air, water, and waste) at three facilities in Geismar, Sorrento, and Chalmette, Louisiana. The audit revealed numerous infractions of Louisiana environmental regulations and resulted in a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality (LDEQ). We agreed with the LDEQ to pay a penalty of $109,000 as a comprehensive multi-media settlement and in July 2007, the LDEQ published the proposed settlement for public review and comment.

     Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws.

Summary of environmental matters

     Actual costs incurred for these matters could be substantially greater than amounts accrued depending on the actual number of contaminated sites identified, the actual amount and extent of contamination discovered, the final cleanup standards mandated by the EPA and other governmental authorities and other factors, but the amount cannot be reasonably estimated at this time.

Other Legal Matters

Will Price (formerly Quinque)

     In 2001, fourteen of our entities were named as defendants in a nationwide class action lawsuit in Kansas state court that had been pending against other defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and sought an unspecified amount of damages. The fourth amended petition, which was filed in 2003, deleted all of our defendant entities except two Midstream subsidiaries. All remaining defendants have opposed class certification and a hearing on plaintiffs’ second motion to certify the class was held in April 2005. We are awaiting a decision from the court.

Grynberg

     In 1998, the DOJ informed us that Jack Grynberg, an individual, had filed claims on behalf of himself and the federal government, in the United States District Court for the District of Colorado under the False Claims Act against us and certain of our wholly owned subsidiaries. The claims sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. In connection with our sales of Kern River Gas Transmission in 2002 and Texas Gas Transmission Corporation in 2003, we agreed to indemnify the purchasers for any liability relating to this claim, including legal fees. The maximum amount of future payments that we could potentially be required to pay under these indemnifications depends upon the ultimate resolution of the claim and cannot currently be determined. Grynberg had also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. In 1999, the DOJ announced

Notes (Continued)

that it would not intervene in any of the Grynberg cases. Also in 1999, the Panel on Multi-District Litigation transferred all of these cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. Grynberg’s measurement claims remained pending against us and the other defendants; the court previously dismissed Grynberg’s royalty valuation claims. In May 2005, the court-appointed special master entered a report which recommended that the claims against our Gas Pipeline and Midstream subsidiaries be dismissed but upheld the claims against our Exploration & Production subsidiaries against our jurisdictional challenge. In October 2006, the District Court dismissed all claims against us and our wholly owned subsidiaries, and in November 2006, Grynberg filed his notice of appeal with the Tenth Circuit Court of Appeals.

     On August 6, 2002, Jack J. Grynberg, and Celeste C. Grynberg, Trustee on Behalf of the Rachel Susan Grynberg Trust, and the Stephen Mark Grynberg Trust, served us and one of our Exploration & Production subsidiaries with a complaint in the state court in Denver, Colorado. The complaint alleges that we have used mismeasurement techniques that distort the BTU heating content of natural gas, resulting in the alleged underpayment of royalties to Grynberg and other independent natural gas producers. The complaint also alleges that we inappropriately took deductions from the gross value of their natural gas and made other royalty valuation errors. Under various theories of relief, the plaintiff is seeking actual damages of between $2 million and $20 million based on interest rate variations and punitive damages in the amount of approximately $1.4 million. In 2004, Grynberg filed an amended complaint against one of our Exploration & Production subsidiaries. This subsidiary filed an answer in January 2005, denying liability for the damages claimed. Trial in this case was originally set for May 2006, but the parties have negotiated an agreement dismissing the measurement claims and deferring further proceedings on the royalty claims until resolution of an appeal in another case.

Securities class actions

     Numerous shareholder class action suits were filed against us in 2002 in the United States District Court for the Northern District of Oklahoma. The majority of the suits alleged that we and co-defendants, WilTel, previously an owned subsidiary known as Williams Communications, and certain corporate officers, acted jointly and separately to inflate the stock price of both companies. WilTel was dismissed as a defendant as a result of its bankruptcy. These cases were consolidated and an order was issued requiring separate amended consolidated complaints by our equity holders and WilTel equity holders. The underwriter defendants have requested indemnification and defense from these cases. If we grant the requested indemnifications to the underwriters, any related settlement costs will not be covered by our insurance policies. We covered the cost of defending the underwriters. In 2002, the amended complaints of the WilTel securities holders and of our securities holders added numerous claims related to WPC. On February 9, 2007, the court gave its final approval to our settlement with our securities holders. We entered into indemnity agreements with certain of our insurers to ensure their timely payment related to this settlement. The carrying value of our estimated liability related to these agreements is immaterial because we believe the likelihood of any future performance is remote.

     On July 6, 2007, the court granted various defendants’ motions for summary judgment and entered judgment for us and the other defendants in the WilTel matter. The plaintiffs filed an appeal. Any obligation of ours to the WilTel equity holders as a result of a settlement, or as a result of trial in the event of a successful appeal of the court’s judgment, will not likely be covered by insurance because our insurance coverage has been fully utilized by the settlement described above. The extent of any such obligation is presently unknown and cannot be estimated, but it is reasonably possible that our exposure could materially exceed amounts accrued for this matter.

TAPS Quality Bank

     One of our subsidiaries, Williams Alaska Petroleum, Inc. (WAPI), is actively engaged in administrative litigation being conducted jointly by the FERC and the Regulatory Commission of Alaska (RCA) concerning the Trans-Alaska Pipeline System (TAPS) Quality Bank. Primary issues being litigated include the appropriate valuation of the naphtha, heavy distillate, vacuum gas oil and residual product cuts within the TAPS Quality Bank as well as the appropriate retroactive effects of the determinations. Due to the sale of WAPI’s interests on March 31, 2004, no future Quality Bank liability will accrue but we are responsible for any liability that existed as of that date, including potential liability for any retroactive payments that might be awarded in these proceedings for the period prior to March 31, 2004. In the third quarter of 2004, the FERC and RCA presiding administrative law judges rendered their joint and individual initial decisions. The initial decisions set forth methodologies for determining the valuations of the product cuts under review and also approved the retroactive application of the approved

Notes (Continued)

methodologies for the heavy distillate and residual product cuts. In 2004, we accrued approximately $134 million based on our computation and assessment of ultimate ruling terms that were considered probable.

     The FERC and the RCA completed their reviews of the initial decisions and in 2005 issued substantially similar orders generally affirming the initial decisions. In June 2006, the FERC, after two sets of rehearing requests, entered its final order (FERC Final Order). During this administrative rehearing process all other appeals of the initial decisions were stayed including ExxonMobil’s appeal to the D.C. Circuit Court of Appeals asserting that the FERC’s reliance on the Highway Reauthorization Act as the basis for limiting the retroactive effect violates, among other things, the separation of powers under the U.S. Constitution by interfering with the FERC’s independent decision-making role. ExxonMobil filed a similar appeal in the Alaska Superior Court. We also appealed the FERC’s order to the extent of its ruling on the West Coast Heavy Distillate component.

     On June 7, 2007, the FERC, in response to requests for clarifications by some parties to the Quality Bank Administrator’s preliminary calculations, stated the Quality Bank Administrator was free to issue invoices without any further action by the FERC. The Quality Bank Administrator issued invoices on July 31, 2007. We estimate that our net obligation for these invoices could be as much as $124 million. This amount remains an estimate since all invoices will not be received directly by WAPI. Some invoices will be directed to other parties who will calculate contributions they believe WAPI owes as a result of the issuance of the Quality Bank invoices. Amounts accrued in excess of this estimated obligation will be retained pending resolution of all appeals.

Redondo Beach taxes

     On February 5, 2005, WPC received a tax assessment letter, addressed to AES Redondo Beach, L.L.C. and WPC, from the city of Redondo Beach, California, in which the city asserted that approximately $33 million in back taxes and approximately $39 million in interest and penalties are owed related to natural gas used at the generating facility operated by AES Redondo Beach. Hearings were held in July 2005 and in September 2005 the tax administrator for the city issued a decision in which he found WPC jointly and severally liable with AES Redondo Beach for back taxes of approximately $36 million and interest and penalties of approximately $21 million. Both WPC and AES Redondo Beach filed notices of appeal that were heard at the city level. On December 13, 2006, the city hearing officer for the appeal of the pre-2005 amounts issued a final decision affirming WPC’s utility user tax liability and reversing AES Redondo Beach’s liability because the officer ruled that AES Redondo Beach is an exempt public utility. WPC appealed this decision to the Los Angeles Superior Court, and the city also appealed with respect to AES Redondo Beach. Those appeals will be heard on January 25, 2008. On April 30, 2007, WPC paid the city the disputed amount of approximately $57 million in order to pursue its appeal. Despite the city hearing officer’s unfavorable decision and the payment to preserve our appeal rights, we do not believe a contingent loss is probable.

     The city’s assessment of our liability for the periods from 1998 through December, 2006 is approximately $69 million (inclusive of interest and penalties). WPC has protested all these assessments and requested hearings on them. WPC and AES Redondo Beach have also filed separate refund actions in Los Angeles Superior Court related to certain taxes paid since the initial 2005 notice of assessment. The refund actions are stayed pending the resolution of the appeals. We believe that under our tolling agreement related to the Redondo Beach generating facility, AES Redondo Beach is responsible for taxes of the nature asserted by the city; however, AES Redondo Beach has notified us that it does not agree. We are pursuing a settlement with AES Redondo Beach of this dispute about our tolling agreement through a sharing of responsibility for any amounts paid or ultimately determined to be payable to the city in this matter.

Gulf Liquids litigation

     Gulf Liquids contracted with Gulsby Engineering Inc. (Gulsby) and Gulsby-Bay for the construction of certain gas processing plants in Louisiana. National American Insurance Company (NAICO) and American Home Assurance Company provided payment and performance bonds for the projects. Gulsby and Gulsby-Bay defaulted on the construction contracts. In the fall of 2001, the contractors, sureties, and Gulf Liquids filed multiple cases in Louisiana and Texas. In January 2002, NAICO added Gulf Liquids’ co-venturer WPC to the suits as a third-party defendant. Gulf Liquids asserted claims against the contractors and sureties for, among other things, breach of contract requesting contractual and consequential damages from $40 million to $80 million, any of which is subject to a sharing arrangement with XL Insurance Company.

Notes (Continued)

     At the conclusion of the consolidated trial of the asserted contract and tort claims, the jury returned its actual damages verdict against WPC and Gulf Liquids on July 31, 2006, and its related punitive damages verdict on August 1, 2006. Based on our interpretation of the jury verdicts, we estimated exposure for actual damages of approximately $68 million plus potential interest of approximately $25 million, all of which have been accrued as of June 30, 2007. In addition, it is reasonably possible that any ultimate judgment may include additional amounts of approximately $199 million in excess of our accrual, which primarily represents our estimate of potential punitive damage exposure under Texas law.

     Although we do not expect the court to enter a final judgment until late in the third quarter of 2007, it recently issued several orders dealing with a part of the issues in the case (interlocutory orders) including:

•

On May 22, 2007, the court denied the contractors’ claims for punitive damages against Gulf Liquids and WPC;

•

On June 18, 2007, the court denied the claims of Bay, one of the joint venturers in Gulsby-Bay, against Gulf Liquids and WPC which were in excess of $30 million;

•

On July 12, 2007, the court awarded Gulsby-Bay approximately $4.4 million on its breach of contract claim against Gulf Liquids;

•

On July 19, 2007, the court awarded $7.7 million to Gulsby on its quantum meruit claim against Gulf Liquids and denied Gulsby any recovery on its tort claims against Gulf Liquids and WPC;

•

On July 20, 2007, the court denied all of NAICO’s claims against Gulsby and WPC which in the aggregate were in excess of $20 million.

If the court’s final judgment incorporates these orders, and the judgment is upheld on appeal, our liability will be less than the amount of our accrual for these matters.

Wyoming severance taxes

     The Wyoming Department of Audit (DOA) audited the severance tax reporting for our subsidiary Williams Production RMT Company for the production years 2000 through 2002. In August 2006, the DOA assessed additional severance tax and interest for those periods of approximately $3 million. In addition, the DOA notified us of an increase in the taxable value of our interests for ad valorem tax purposes, which is estimated to result in additional taxes of approximately $2 million, including interest. We dispute the DOA’s interpretation of the statutory obligation and have appealed this assessment to the Wyoming State Board of Equalization. If the DOA prevails in its interpretation of our obligation and applies the same basis of assessment to subsequent periods, it is reasonably possible that we could owe a total of approximately $24 million to $26 million in taxes and interest from January 1, 2003, through June 30, 2007.

Royalty litigation

     In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in Colorado state court alleging that we improperly calculated oil and gas royalty payments, failed to account for the proceeds that we received from the sale of gas and extracted products, improperly charged certain expenses, and failed to refund amounts withheld in excess of ad valorem tax obligations. The plaintiffs claim that the class might be in excess of 500 individuals and seek an accounting and damages. The parties have agreed to stay this action in order to participate in ongoing mediation.

Other Divestiture Indemnifications

     Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.

Notes (Continued)

     We sold a natural gas liquids pipeline system in 2002, and in July 2006, the purchaser of that system filed its complaint against us and our subsidiaries in state court in Houston, Texas. The purchaser alleges that we breached certain warranties under the purchase and sale agreement and seeks approximately $18.5 million in damages and our specific performance under certain guarantees. In 2006, we filed our answer to the purchaser’s complaint denying all liability. We anticipate that the trial will occur in the first quarter of 2008, and our prior suit filed against the purchaser in Delaware state court is stayed pending resolution of the Texas case.

     At June 30, 2007, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on results of operations in the period in which the claim is made.

     In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.

Summary

     Litigation, arbitration, regulatory matters, and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a materially adverse effect upon our future financial position.

Commitments

     WPC has entered into certain contracts giving it the right to receive fuel conversion services as well as certain other services associated with electric generation facilities that are currently in operation throughout the continental United States. At June 30, 2007, WPC’s estimated committed payments under these contracts range from approximately $410 million to $425 million annually through 2017 and decline over the remaining five years to $59 million in 2022. Total committed payments under these contracts over the next sixteen years are approximately $5.3 billion. These contracts are included in the pending sale of our power business to Bear Energy, LP. (See Note 3.)

Guarantees

     In connection with agreements executed prior to our acquisition of Transco to resolve take-or-pay and other contract claims and to amend gas purchase contracts, Transco entered into certain settlements with producers which may require the indemnification of certain claims for additional royalties that the producers may be required to pay as a result of such settlements. Transco, through its agent, Gas Marketing Services, continues to purchase gas under contracts which extend, in some cases, through the life of the associated gas reserves. Certain of these contracts contain royalty indemnification provisions that have no carrying value. Producers have received certain demands and may receive other demands, which could result in claims pursuant to royalty indemnification provisions. Indemnification for royalties will depend on, among other things, the specific lease provisions between the producer and the lessor and the terms of the agreement between the producer and Transco. Consequently, the potential maximum future payments under such indemnification provisions cannot be determined. However, management believes that the probability of material payments is remote.

     In connection with the 1993 public offering of units in the Williams Coal Seam Gas Royalty Trust (Royalty Trust), our Exploration & Production segment entered into a gas purchase contract for the purchase of natural gas in which the Royalty Trust holds a net profits interest. Under this agreement, we guarantee a minimum purchase price that the Royalty Trust will realize in the calculation of its net profits interest. We have an annual option to discontinue this minimum purchase price guarantee and pay solely based on an index price. The maximum potential future exposure associated with this guarantee is not determinable because it is dependent upon natural gas prices and production volumes. No amounts have been accrued for this contingent obligation as the index price continues to substantially exceed the minimum purchase price.

     We are required by certain foreign lenders to ensure that the interest rates received by them under various loan agreements are not reduced by taxes by providing for the reimbursement of any domestic taxes required to be paid by the foreign lender. The maximum potential amount of future payments under these indemnifications is based on

Notes (Continued)

the related borrowings. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications.

     We have guaranteed commercial letters of credit totaling $20 million on behalf of a certain entity in which we have an equity ownership interest. These expire by January 2008 and have no carrying value.

     We have provided guarantees on behalf of certain entities in which we have an equity ownership interest. These generally guarantee operating performance measures and the maximum potential future exposure cannot be determined. There are no expiration dates associated with these guarantees. No amounts have been accrued at June 30, 2007.

     We have provided guarantees in the event of nonpayment by our previously owned communications subsidiary, WilTel, on certain lease performance obligations that extend through 2042. The maximum potential exposure is approximately $45 million at June 30, 2007. Our exposure declines systematically throughout the remaining term of WilTel’s obligations. The carrying value of these guarantees is approximately $41 million at June 30, 2007.

     Former managing directors of Gulf Liquids are involved in litigation related to the construction of gas processing plants. Gulf Liquids has indemnity obligations to the former managing directors for legal fees and potential losses that may result from this litigation. Claims against these former managing directors have been settled and dismissed after payments on their behalf by directors and officers insurers. Some unresolved issues remain between us and these insurers, but no amounts have been accrued for any potential liability.

     We have guaranteed the performance of a former subsidiary of our wholly owned subsidiary MAPCO Inc., under a coal supply contract. This guarantee was granted by MAPCO Inc. upon the sale of its former subsidiary to a third-party in 1996. The guaranteed contract provides for an annual supply of a minimum of 2.25 million tons of coal. Our potential exposure is dependent on the difference between current market prices of coal and the pricing terms of the contract, both of which are variable, and the remaining term of the contract. Given the variability of the terms, the maximum future potential payments cannot be determined. We believe that our likelihood of performance under this guarantee is remote. In the event we are required to perform, we are fully indemnified by the purchaser of MAPCO Inc.’s former subsidiary. This guarantee expires in December 2010 and has no carrying value.

Note 12. Comprehensive Income (Loss)

     Comprehensive income (loss) is as follows:

		Three months ended								Six months ended
		June 30,								June 30,
		2007				2006				2007				2006
		(Millions)								(Millions)
Net income (loss)		$	433.1			$	(76.0	)		$	567.1			$	55.9
Other comprehensive income (loss):
Net unrealized gains on derivative instruments			111.2				45.2				121.2				234.2
Net reclassification into earnings of derivative instrument (gains) losses			(453.8	)			32.9				(443.9	)			134.3
Foreign currency translation adjustments			28.4				12.5				31.5				10.3
Minimum pension liability adjustment			—				—				—				(.3	)
Pension benefits:
Amortization of prior service credit			(.1	)			—				(.2	)			—
Amortization of net actuarial loss			5.1				—				9.1				—
Other postretirement benefits:
Amortization of prior service cost			.2				—				.5				—
Other comprehensive income (loss) before taxes			(309.0	)			90.6				(281.8	)			378.5
Income tax benefit (provision) on other comprehensive income (loss)			129.2				(29.8	)			119.9				(140.9	)
Other comprehensive income (loss)			(179.8	)			60.8				(161.9	)			237.6
Comprehensive income (loss)		$	253.3			$	(15.2	)		$	405.2			$	293.5

     During second-quarter 2007, in anticipation of signing a definitive agreement to sell our power business (see Note 3), we concluded that certain power and gas hedged forecasted transactions were no longer probable of occurring and therefore discontinued hedge accounting prospectively and began recognizing changes in fair value directly in earnings.

Notes (Continued)

     We subsequently concluded that the completion of the sale of our power business was probable and therefore we concluded that it was probable that certain related forecasted transactions designated as the hedged items in cash flow hedges would not occur. We have therefore recognized in our second-quarter 2007 earnings $429.3 million (reflected in net reclassification into earnings of derivative instruments (gains) losses) of net unrealized hedge gains which were previously deferred in accumulated other comprehensive income. For the quarter and year-to-date ended June 30, 2007, this amount is reported in income (loss) from discontinued operations. (See Note 3.)

     Net unrealized gains on derivative instruments represents changes in the fair value of certain derivative contracts that have been designated as cash flow hedges. The net unrealized gains for the six months ending June 30, 2007, include net unrealized gains on forward natural gas purchases and sales of approximately $152 million, partially offset by net unrealized losses on forward power purchases and sales of approximately $31 million. The net unrealized gains for the six months ending June 30, 2006, include net unrealized gains on forward power purchases and sales of approximately $94 million, net unrealized gains on forward natural gas purchases and sales of approximately $160 million, and net unrealized losses on forward natural gas liquids sales of approximately $21 million. As of June 30, 2007, there are no remaining unrealized hedge gains or losses related to forward power purchases and sales deferred in accumulated other comprehensive income.

     Our Midstream segment sells natural gas liquids produced by our processing plants. To reduce the exposure to changes in market prices, we have entered into natural gas liquids swap agreements or forward contracts to fix the prices of a limited portion of our anticipated sales of natural gas liquids. These cash flow hedges are expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item.

Note 13. Segment Disclosures

     On May 21, 2007, we announced that we had entered into a definitive agreement to sell substantially all of our power business to Bear Energy, LP. This pending sale has impacted our segment presentation. See Notes 2 and 3 for further discussion.

     Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different technology, marketing strategies and industry knowledge. Our master limited partnership, Williams Partners L.P., is consolidated within our Midstream segment. (See Note 2.) Other primarily consists of corporate operations and our Milagro natural gas-fired electric generating plant. (See Note 3.)

Performance Measurement

     We currently evaluate performance based upon segment profit (loss) from operations, which includes segment revenues from external and internal customers, segment costs and expenses, depreciation, depletion and amortization, equity earnings (losses) and income (loss) from investments including impairments related to investments accounted for under the equity method. Intersegment sales are generally accounted for at current market prices as if the sales were to unaffiliated third parties.

     The majority of energy commodity hedging by certain of our business units was historically done through intercompany derivatives with our former Power segment which, in turn, entered into offsetting derivative contracts with unrelated third parties. Power bore the counterparty performance risks associated with unrelated third parties. These operations continue in our new Gas Marketing Services segment. However, beginning in the first quarter of 2007, hedges related to Exploration & Production may be entered into directly between Exploration & Production and third parties under its new credit agreement. (See Note 10.)

     The Gas Marketing Services segment includes the continued marketing and risk management operations that support our natural gas businesses. The operations include marketing and hedging the gas produced by Exploration & Production and procuring fuel and shrink gas for Midstream. In addition, Gas Marketing Services manages various natural gas-related contracts such as transportation, storage, and related hedges.

     External revenues of our Exploration & Production segment include third-party oil and gas sales, which are more than offset by transportation expenses and royalties due third parties on intersegment sales.

Notes (Continued)

     The following tables reflect the reconciliation of segment revenues and segment profit (loss) to revenues and operating income as reported in the Consolidated Statement of Operations.

		Exploration								Midstream				Gas
		&				Gas				Gas &				Marketing
		Production				Pipeline				Liquids				Services				Other				Eliminations				Total
		(Millions)
Three months ended June 30, 2007
Segment revenues:
External		$	(13.7	)		$	407.7			$	1,224.0			$	1,195.1			$	10.3			$	—			$	2,823.4
Internal			553.2				7.1				10.3				198.3				4.6				(773.5	)			—
Total revenues		$	539.5			$	414.8			$	1,234.3			$	1,393.4			$	14.9			$	(773.5	)		$	2,823.4
Segment profit (loss)		$	209.4			$	174.3			$	249.6			$	(63.5	)		$	1.2			$	—			$	571.0
Less:
Equity earnings (losses)			4.9				9.3				8.7				—				(.1	)			—				22.8
Segment operating income (loss)		$	204.5			$	165.0			$	240.9			$	(63.5	)		$	1.3			$	—				548.2
General corporate expenses																											(36.2	)
Total operating income																										$	512.0
Three months ended June 30, 2006
Segment revenues:
External		$	(35.9	)		$	333.8			$	1,029.6			$	886.7			$	5.7			$	—			$	2,219.9
Internal			378.2				3.5				13.9				230.1				7.3				(633.0	)			—
Total revenues		$	342.3			$	337.3			$	1,043.5			$	1,116.8			$	13.0			$	(633.0	)		$	2,219.9
Segment profit (loss)		$	119.8			$	122.7			$	131.0			$	(65.6	)		$	(3.9	)		$	—			$	304.0
Less:
Equity earnings			5.9				10.7				6.5				—				—				—				23.1
Loss from investments			—				(.5	)			—				—				—				—				(.5	)
Segment operating income (loss)		$	113.9			$	112.5			$	124.5			$	(65.6	)		$	(3.9	)		$	—				281.4
General corporate expenses																											(33.7	)
Securities litigation settlement and related costs																											(160.7	)
Total operating income																										$	87.0

		Exploration								Midstream				Gas
		&				Gas				Gas &				Marketing
		Production				Pipeline				Liquids				Services				Other				Eliminations				Total
		(Millions)
Six months ended June 30, 2007
Segment revenues:
External		$	(76.1	)		$	770.7			$	2,208.1			$	2,269.4			$	19.6			$	—			$	5,191.7
Internal			1,098.3				14.9				21.6				412.3				8.9				(1,556.0	)			—
Total revenues		$	1,022.2			$	785.6			$	2,229.7			$	2,681.7			$	28.5			$	(1,556.0	)		$	5,191.7
Segment profit (loss)		$	397.5			$	324.0			$	403.7			$	(93.3	)		$	.9			$	—			$	1,032.8
Less:
Equity earnings			10.2				18.6				15.4				—				—				—				44.2
Segment operating income (loss)		$	387.3			$	305.4			$	388.3			$	(93.3	)		$	.9			$	—				988.6
General corporate expenses																											(75.6	)
Total operating income																										$	913.0
Six months ended June 30, 2006
Segment revenues:
External		$	(95.4	)		$	664.3			$	1,995.7			$	2,027.2			$	15.3			$	—			$	4,607.1
Internal			793.7				7.0				27.2				513.7				16.8				(1,358.4	)			—
Total revenues		$	698.3			$	671.3			$	2,022.9			$	2,540.9			$	32.1			$	(1,358.4	)		$	4,607.1
Segment profit (loss)		$	267.4			$	257.4			$	282.3			$	(88.7	)		$	(3.2	)		$	—			$	715.2
Less:
Equity earnings			10.9				18.2				16.2				—				—				—				45.3
Loss from investments			—				(.5	)			—				—				—				—				(.5	)
Segment operating income (loss)		$	256.5			$	239.7			$	266.1			$	(88.7	)		$	(3.2	)		$	—				670.4
General corporate expenses																											(64.3	)
Securities litigation settlement and related costs																											(161.9	)
Total operating income																										$	444.2