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, 2006

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, 2006
Common Stock, $1 par value		595,800,152 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, 2006 and 2005			2
Consolidated Balance Sheet — June 30, 2006 and December 31, 2005			3
Consolidated Statement of Cash Flows — Six Months Ended June 30, 2006 and 2005			4
Notes to Consolidated Financial Statements			5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			26
Item 3. Quantitative and Qualitative Disclosures about Market Risk			52
Item 4. Controls and Procedures			54
Part II. Other Information			55
Item 1. Legal Proceedings			55
Item 1A. Risk Factors			55
Item 4. Submission of Matters to a Vote of Security Holders			55
Item 6. Exhibits			56
Computation of Ratio of Earnings to Fixed Charges
Certification of CEO Pursuant to Rule 13a-14(a) and 15d-14(a)
Certification of CFO Pursuant to Rule 13a-14(a) and 15d-14(a)
Certification of CEO and CFO Pursuant to Section 1350

     Certain matters discussed in this report, excluding historical information, include forward-looking statements — statements that 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.

     Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “expects,” “planned,” “scheduled,” “could,” “may,” “should,” “continues,” “estimates,” “forecasts,” “might,” “potential,” “projects” or similar expressions. Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this document. Additional information about issues that could cause actual results to differ materially from forward-looking statements is contained in our 2005 Form 10-K.

The Williams Companies, Inc.

		Three months								Six months
		ended June 30,								ended June 30,
(Dollars in millions, except per-share amounts)		2006				2005				2006				2005
Revenues:
Exploration & Production		$	342.3			$	281.5			$	698.3			$	530.5
Gas Pipeline			337.3				357.0				671.3				692.3
Midstream Gas & Liquids			1,043.5				780.1				2,022.9				1,587.1
Power			1,607.0				1,999.4				3,660.2				4,064.3
Other			6.5				6.1				13.4				13.1
Intercompany eliminations			(621.5	)			(552.9	)			(1,323.5	)			(1,062.1	)
Total revenues			2,715.1				2,871.2				5,742.6				5,825.2
Segment costs and expenses:
Costs and operating expenses			2,273.8				2,491.6				4,862.5				4,881.9
Selling, general and administrative expenses			109.3				62.7				180.3				136.2
Other expense — net			61.7				21.9				39.4				20.1
Total segment costs and expenses			2,444.8				2,576.2				5,082.2				5,038.2
General corporate expenses			33.7				35.5				64.3				63.5
Securities litigation settlement and related costs			160.7				—				161.9				—
Operating income (loss):
Exploration & Production			113.9				114.7				256.5				214.9
Gas Pipeline			112.5				156.6				239.7				312.6
Midstream Gas & Liquids			124.5				104.3				266.1				225.8
Power			(79.9	)			(75.9	)			(102.2	)			37.1
Other			(.7	)			(4.7	)			.3				(3.4	)
General corporate expenses			(33.7	)			(35.5	)			(64.3	)			(63.5	)
Securities litigation settlement and related costs			(160.7	)			—				(161.9	)			—
Total operating income			75.9				259.5				434.2				723.5
Interest accrued			(181.5	)			(164.6	)			(344.3	)			(329.3	)
Interest capitalized			4.0				1.4				7.0				2.5
Investing income (loss)			43.3				(17.2	)			90.2				13.8
Early debt retirement costs			(4.4	)			—				(31.4	)			—
Minority interest in income of consolidated subsidiaries			(8.3	)			(4.8	)			(15.4	)			(10.0	)
Other income — net			8.0				8.1				16.1				13.6
Income (loss) from continuing operations before income taxes			(63.0	)			82.4				156.4				414.1
Provision for income taxes			0.9				41.7				89.2				171.2
Income (loss) from continuing operations			(63.9	)			40.7				67.2				242.9
Income (loss) from discontinued operations			(12.1	)			.6				(11.3	)			(.5	)
Net income (loss)		$	(76.0	)		$	41.3			$	55.9			$	242.4
Basic earnings (loss) per common share:
Income (loss) from continuing operations		$	(.11	)		$	.07			$	.11			$	.43
Income (loss) from discontinued operations			(.02	)			—				(.02	)			—
Net income (loss)		$	(.13	)		$	.07			$	.09			$	.43
Weighted-average shares (thousands)			595,561				571,208				593,495				567,841
Diluted earnings (loss) per common share:
Income (loss) from continuing operations		$	(.11	)		$	.07			$	.11			$	.41
Income (loss) from discontinued operations			(.02	)			—				(.02	)			—
Net income (loss)		$	(.13	)		$	.07			$	.09			$	.41
Weighted-average shares (thousands)			595,561				578,902				598,634				602,956
Cash dividends per common share		$	.09			$	.05			$	.165			$	.10

See accompanying notes.

The Williams Companies, Inc.

		June 30,				December 31,
(Dollars in millions, except per-share amounts)		2006				2005
ASSETS
Current assets:
Cash and cash equivalents		$	980.4			$	1,597.2
Restricted cash			79.7				92.9
Accounts and notes receivable (net of allowance of $21.1 in 2006 and $86.6 in 2005)			1,164.9				1,613.8
Inventories			307.7				272.6
Derivative assets			2,725.2				5,299.7
Margin deposits			273.5				349.2
Assets of discontinued operations			12.8				12.8
Deferred income taxes			314.1				241.0
Other current assets and deferred charges			565.4				218.1
Total current assets			6,423.7				9,697.3
Restricted cash			38.2				36.5
Investments			933.7				887.8
Property, plant and equipment — net			13,004.0				12,409.2
Derivative assets			3,427.3				4,656.9
Goodwill			1,014.5				1,014.5
Other assets and deferred charges			775.8				740.4
Total assets		$	25,617.2			$	29,442.6
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	971.3			$	1,360.6
Accrued liabilities			1,293.3				1,121.9
Customer margin deposits payable			32.3				320.7
Liabilities of discontinued operations			1.2				1.2
Derivative liabilities			2,770.8				5,523.2
Long-term debt due within one year			170.7				122.6
Total current liabilities			5,239.6				8,450.2
Long-term debt			7,292.6				7,590.5
Deferred income taxes			2,752.9				2,508.9
Derivative liabilities			3,070.5				4,331.1
Other liabilities and deferred income			941.4				920.3
Contingent liabilities and commitments (Note 11)
Minority interests in consolidated subsidiaries			437.9				214.1
Stockholders’ equity
Common stock (960 million shares authorized at $1 par value; 601.2 million issued at June 30, 2006 and 579.1 million shares issued at December 31, 2005)			601.2				579.1
Capital in excess of par value			6,560.9				6,327.8
Accumulated deficit			(1,178.3	)			(1,135.9	)
Accumulated other comprehensive loss			(60.2	)			(297.8	)
Other			(.1	)			(4.5	)
			5,923.5				5,468.7
Less treasury stock, at cost (5.7 million shares of common stock in 2006 and 2005)			(41.2	)			(41.2	)
Total stockholders’ equity			5,882.3				5,427.5
Total liabilities and stockholders’ equity		$	25,617.2			$	29,442.6

See accompanying notes.

The Williams Companies, Inc.

		Six months ended June 30,
(Dollars in millions)		2006				2005
OPERATING ACTIVITIES:
Net income		$	55.9			$	242.4
Adjustments to reconcile to net cash provided by operations:
Loss from discontinued operations			11.3				.5
Depreciation, depletion and amortization			407.5				356.3
Accrual for securities litigation settlement and related costs			161.9				—
Provision for deferred income taxes			47.6				149.6
Provision for loss on investments, property and other assets			4.0				53.5
Net gain on disposition of assets			(9.8	)			(20.7	)
Early debt retirement costs			31.4				—
Minority interest in income of consolidated subsidiaries			15.4				10.0
Amortization of stock-based awards			21.4				6.8
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable			440.7				172.7
Inventories			(35.0	)			1.6
Margin deposits and customer margin deposits payable			(212.7	)			74.6
Other current assets and deferred charges			(61.0	)			(7.2	)
Accounts payable			(300.7	)			(126.8	)
Accrued liabilities			(67.0	)			(68.9	)
Changes in current and noncurrent derivative assets and liabilities			158.8				(27.3	)
Other, including changes in noncurrent assets and liabilities			3.6				(23.8	)
Net cash provided by operating activities			673.3				793.3
FINANCING ACTIVITIES:
Proceeds from long-term debt			699.4				—
Payments of long-term debt			(728.2	)			(220.7	)
Proceeds from issuance of common stock			15.0				296.6
Proceeds from sale of limited partner units of consolidated partnership			225.2				—
Tax benefit of stock-based awards			5.2				—
Payments for debt issuance costs and amendment fees			(26.9	)			(19.4	)
Premiums paid on early debt retirement			(25.8	)			—
Dividends paid			(98.2	)			(57.1	)
Dividends and distributions paid to minority interests			(16.8	)			(14.3	)
Changes in restricted cash			7.1				21.2
Changes in cash overdrafts			(63.4	)			26.9
Other — net			(1.1	)			—
Net cash provided (used) by financing activities			(8.5	)			33.2
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures			(1,002.6	)			(516.6	)
Proceeds from dispositions			3.7				9.6
Proceeds from contract termination payment			3.3				87.9
Purchases of investments/advances to affiliates			(36.5	)			(81.9	)
Purchases of auction rate securities			(327.3	)			(155.3	)
Proceeds from sales of auction rate securities			21.8				100.3
Proceeds received on sale of note from WilTel			—				54.7
Proceeds from dispositions of investments and other assets			51.3				35.4
Other — net			4.7				6.6
Net cash used by investing activities			(1,281.6	)			(459.3	)
Increase (decrease) in cash and cash equivalents			(616.8	)			367.2
Cash and cash equivalents at beginning of period			1,597.2				930.0
Cash and cash equivalents at end of period		$	980.4			$	1,297.2

See accompanying notes.

The Williams Companies, Inc.

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, 2006, and results of operations for the three and six months ended June 30, 2006 and 2005 and cash flows for the six months ended June 30, 2006 and 2005.

     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

     Amounts presented as discontinued operations in our financial statements relate to residual activity and/or adjustments from businesses that were sold in prior years. The most recent such sale closed in July 2004.

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

     Certain amounts have been reclassified to conform to current classifications.

     In February 2005, we formed Williams Partners L.P., a limited partnership engaged in the business of gathering, transporting and processing natural gas and fractionating and storing natural gas liquids. In August 2005, we completed our initial public offering of five million common units of Williams Partners L.P. We currently own approximately 39 percent of Williams Partners L.P., including the interests of the general partner, which is wholly-owned by us. Considering the presumption of control of the general partner 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,” Williams Partners L.P. is consolidated within our Midstream Gas & Liquids (Midstream) segment.

Notes (Continued)

Note 3. Asset Sales, Impairments and Other Accruals

     Significant gains or losses from asset sales, impairments and other accruals or adjustments reflected in our Consolidated Statement of Operations are included in the following table:

		Three months ended								Six months ended
		June 30,								June 30,
		2006				2005				2006				2005
		(Millions)								(Millions)
Costs and operating expenses:
Gas Pipeline
Adjustments to correct the carrying value of certain liabilities recorded in prior periods		$	—			$	4.6			$	—			$	12.1
Selling, general and administrative expenses:
Gas Pipeline
Adjustments to correct the carrying value of certain liabilities recorded in prior periods			—				—				—				5.6
Reduction in pension expense for the cumulative impact of correcting an error attributable to 2003 and 2004			—				17.1				—				17.1
Other expense — net (within segment costs and expenses):
Midstream
Accrual for Gulf Liquids litigation contingency. Associated with this contingency is an interest expense accrual of $20 million, which is included in interest accrued (see Note 11)			68.0				—				68.0				—
Settlement of an international contract dispute			—				—				9.0				—
Gas Pipeline
Reversal of an accrued litigation contingency due to a favorable court ruling. Associated with this contingency reversal is $5 million of income due to reversing accrued interest, which is included in interest accrued			—				—				2.0				—
Power
Accrual for litigation contingencies			—				13.1				—				13.1
Securities litigation settlement and related costs (see Note 11)			160.7				—				161.9				—
Investing income (loss):
Midstream
Gain on sale of remaining interests in Mid-America Pipeline (MAPL) and Seminole Pipeline (Seminole)			—				8.6				—				8.6
Other
Impairment of investment in Longhorn Partners Pipeline L.P. (Longhorn)			—				(49.1	)			—				(49.1	)
Income (loss) from discontinued operations:
$19.2 million accrual for an adverse arbitration award related to our former chemical fertilizer business, net of taxes of $7.3 million (see Note 11)			(11.9	)			—				(11.9	)			—

Note 4. Provision for Income Taxes

     The provision for income taxes includes:

		Three months ended								Six months ended
		June 30,								June 30,
		2006				2005				2006				2005
		(Millions)								(Millions)
Current:
Federal		$	9.6			$	3.0			$	12.7			$	7.3
State			9.1				2.8				11.7				8.0
Foreign			9.2				5.2				17.2				6.3
			27.9				11.0				41.6				21.6
Deferred:
Federal			(23.7	)			36.2				32.7				139.1
State			(8.4	)			.1				4.2				16.1
Foreign			5.1				(5.6	)			10.7				(5.6	)
			(27.0	)			30.7				47.6				149.6
Total provision		$	0.9			$	41.7			$	89.2			$	171.2

Notes (Continued)

     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 the effect of state income taxes, net foreign operations, estimated nondeductible expenses associated with our securities litigation settlement and fees, and nondeductible expenses associated with the conversion of convertible debentures.

     The effective income tax rate for the three and six months ended June 30, 2005, is greater than the federal statutory rate due primarily to the effect of state income taxes, nondeductible expenses and an accrual for income tax contingencies.

Note 5. 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,
		2006				2005				2006				2005
		(Dollars in millions,								(Dollars in millions,
		except per-share								except per-share
		amounts; shares in								amounts; shares in
		thousands)								thousands)
Income (loss) from continuing operations available to common stockholders for basic and diluted earnings per share (1)		$	(63.9	)		$	40.7			$	67.2			$	242.9
Basic weighted-average shares (2)			595,561				571,208				593,495				567,841
Effect of dilutive securities:
Unvested deferred shares (3)			—				2,980				865				2,774
Stock options			—				4,714				4,274				4,793
Convertible debentures			—				—				—				27,548
Diluted weighted-average shares			595,561				578,902				598,634				602,956
Earnings (loss) per share from continuing operations:
Basic		$	(.11	)		$	.07			$	.11			$	.43
Diluted		$	(.11	)		$	.07			$	.11			$	.41

     Approximately 7.3 million, 8.9 million and 27.5 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 and the three months ended June 30, 2005, respectively. Inclusion of these shares would have an antidilutive effect on diluted earnings per common share. If no other components used to calculate diluted earnings per common share change, we estimate the assumed conversion of convertible debentures would have become dilutive and therefore be included in diluted earnings per common share at an income from continuing operations available to common stockholders amount of $55.6 million and $112.3 million for the three and six months ended June 30, 2006, and $53.5 million for the three months ended June 30, 2005.

Notes (Continued)

     The table below includes information related to 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,
		2006				2005
Options excluded (millions)		$	4.3			$	8.8
Weighted-average exercise prices of options excluded		$	35.29			$	28.31
Exercise price ranges of options excluded		$	22.12-$42.29			$	18.15-$42.29
Second quarter weighted-average market price		$	21.96			$	18.12

     In addition, 4.3 million options with exercise prices less than the second quarter weighted-average market price have been excluded from the computation of the 2006 weighted-average stock options due to the shares being anti-dilutive as a result of our adoption of Financial Accounting Standards Board (FASB) Statement No. 123(R), “Share-Based Payment” (SFAS No. 123(R)), during the first quarter of 2006 (see Note 7). These excluded shares have a weighted-average exercise price of $19.91.

Note 6. Employee Benefit Plans

     Net periodic pension expense (income) and other postretirement benefit expense for the three and six months ended June 30, 2006 and 2005 are as follows:

		Pension Benefits
		Three months								Six months
		ended June 30,								ended June 30,
		2006				2005				2006				2005
		(Millions)								(Millions)
Components of net periodic pension expense (income):
Service cost		$	5.4			$	4.7			$	11.1			$	10.8
Interest cost			13.1				11.8				24.9				23.8
Expected return on plan assets			(16.5	)			(20.3	)			(33.4	)			(35.5	)
Amortization of prior service cost (credit)			(.2	)			.2				(.3	)			(.2	)
Recognized net actuarial (gain) loss			5.7				(13.2	)			9.5				(10.0	)
Regulatory asset amortization (deferral)			—				(.9	)			(.1	)			(.4	)
Settlement/curtailment expense			—				.7				—				2.6
Net periodic pension expense (income)		$	7.5			$	(17.0	)		$	11.7			$	(8.9	)

		Other Postretirement Benefits
		Three months								Six months
		ended June 30,								ended June 30,
		2006				2005				2006				2005
		(Millions)								(Millions)
Components of net periodic other postretirement benefit expense:
Service cost		$	.7			$	.6			$	1.6			$	1.5
Interest cost			3.4				5.1				8.6				8.8
Expected return on plan assets			(2.7	)			(2.4	)			(5.6	)			(5.7	)
Amortization of prior service credit			(.1	)			(2.9	)			(.2	)			(4.1	)
Recognized net actuarial (gain) loss			(.9	)			1.5				—				1.5
Regulatory asset amortization			2.0				2.2				3.6				3.8
Net periodic other postretirement benefit expense		$	2.4			$	4.1			$	8.0			$	5.8

     Net periodic pension expense (income) for the three and six months ended June 30, 2005, includes a $17.1 million reduction to expense to record the cumulative impact of a correction of an error determined to have occurred in 2003 and 2004. The error was associated with our third-party actuarial computation of annual net periodic pension expense which resulted from the identification of errors in certain Transcontinental Gas Pipe Line Corporation (Transco) participant data involving annuity contract information utilized for 2003 and 2004. The adjustment is reflected as $16.1 million within recognized net actuarial (gain) loss and $1 million within regulatory asset amortization (deferral).

     Through June 30, 2006, we have contributed $2.9 million to our pension plans and $7.4 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $14 million to our pension plans in 2006 for a total of approximately $17 million. We presently anticipate making additional contributions of approximately $8 million to our other postretirement benefit plans in 2006 for a total of approximately $15 million.

Notes (Continued)

Note 7. Stock-Based Compensation

Plan Information

     The Williams Companies, Inc. 2002 Incentive Plan (the Plan) was approved by stockholders on May 16, 2002, and amended and restated on May 15, 2003, and January 23, 2004. The Plan provides for common-stock-based awards to both employees and nonmanagement directors. Upon approval by the stockholders, all prior stock plans were terminated resulting in no further grants being made from those plans. However, awards outstanding in those prior plans remain in those plans with their respective terms and provisions.

     The Plan permits the granting of various types of awards including, but not limited to, stock options and deferred stock. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved. At June 30, 2006, 43.3 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 19.8 million shares were available for future grants. At December 31, 2005, 45 million shares of our common stock were reserved for issuance, of which 21.6 million were available for future grants.

Accounting for Stock-Based Compensation

     Prior to January 1, 2006, we accounted for the Plan under the recognition and measurement provisions of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, as permitted by FASB Statement No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). Compensation cost for stock options was not recognized in the Consolidated Statement of Operations for the six months ending June 30, 2005, as all options granted under the Plan had an exercise price equal to the market value of the underlying common stock on the date of the grant. Prior to January 1, 2006, compensation cost was recognized for deferred share awards. Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No. 123(R), using the modified-prospective method. Under this method, compensation cost recognized in the first six months of 2006 includes: (1) compensation cost for all share-based payments granted through December 31, 2005, but for which the requisite service period had not been completed as of December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123, and (2) compensation cost for all share-based payments granted subsequent to December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R). Results for prior periods have not been restated.

     Total stock-based compensation expense for the three and six months ending June 30, 2006, was $10.9 million and $21.4 million, respectively. The year-to-date amount reflects a reduction of $.3 million of previously recognized compensation cost for deferred share awards related to the estimated number of awards expected to be forfeited. This adjustment is not considered material for reporting as a cumulative effect of a change in accounting principle. Measured but unrecognized stock-based compensation expense at June 30, 2006, was approximately $70 million, which does not include the effect of estimated forfeitures of $2.6 million. This amount is comprised of approximately $21 million related to stock options and approximately $49 million related to deferred shares. These amounts are expected to be recognized over a weighted-average period of two years.

     As a result of adopting SFAS No. 123(R), our income (loss) from continuing operations before income taxes and net income (loss) for the three months ending June 30, 2006, are approximately $4.3 million and $2.7 million lower, respectively, and for the six months ending June 30, 2006, are approximately $10.6 million and $6.6 million lower, respectively, than if we continued to account for share-based compensation under APB No. 25. For the six months ending June 30, 2006, basic and diluted earnings per share are $.01 lower due to the implementation of SFAS No. 123(R).

     The following table illustrates the effect on net income and earnings per common share if we had applied the fair value recognition provisions to SFAS No. 123 to options granted under the Plan for the three and six months ending June 30, 2005. For purposes of this pro forma disclosure, the value of the options was estimated using a Black-Scholes option pricing model and amortized to expense over the vesting period of the options.

Notes (Continued)

		Three months ended				Six months ended
		June 30, 2005				June 30, 2005
		(Dollars in millions, except				(Dollars in millions, except
		per share amounts)				per share amounts)
Net income, as reported		$	41.3			$	242.4
Add: Stock-based employee compensation expense included in the Consolidated Statement of Operations, net of related tax effects			2.2				4.0
Deduct: Stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects			(2.6	)			(8.0	)
Pro forma net income		$	40.9			$	238.4
Earnings per share:
Basic-as reported		$	.07			$	.43
Basic-pro forma		$	.07			$	.42
Diluted-as reported		$	.07			$	.41
Diluted-pro forma		$	.07			$	.40

Stock Options

     Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.

     The following summary reflects stock option activity and related information for the six-month period ending June 30, 2006.

						Weighted-
						Average				Aggregate
						Exercise				Intrinsic
Stock Options		Options				Price				Value
		(Millions)								(Millions)
Outstanding at December 31, 2005			20.4			$	16.63
Granted			1.2			$	21.62
Exercised			(1.4	)		$	11.09			$	15.0
Cancelled			(.5	)		$	30.35
Outstanding at June 30, 2006			19.7			$	16.97			$	159.6
Exercisable at June 30, 2006			15.1			$	16.93			$	136.2

     The following summary provides additional information about stock options that are outstanding and exercisable at June 30, 2006.

		Stock Options Outstanding												Stock Options Exercisable
										Weighted-												Weighted-
						Weighted-				Average								Weighted-				Average
						Average				Remaining								Average				Remaining
						Exercise				Contractual								Exercise				Contractual
Range of Exercise Prices		Options				Price				Life				Options				Price				Life
		(Millions)								(Years)				(Millions)								(Years)
$  2.27 to $10.00			9.4			$	7.14				6.2				8.0			$	6.67				6.0
$10.38 to $16.40			1.2			$	15.50				3.9				1.2			$	15.56				3.8
$17.10 to $31.58			5.8			$	21.30				7.1				2.6			$	22.79				4.7
$33.51 to $42.28			3.3			$	37.63				2.0				3.3			$	37.63				2.0
Total			19.7			$	16.97				5.6				15.1			$	16.93				4.7

Notes (Continued)

     The estimated weighted-average grant-date fair value of stock options granted during the first six months of 2006 is $8.34 per share. We used the Black-Scholes option pricing model to estimate the grant-date fair value of each stock option granted. The fair values of options granted during the first six months of 2006 were estimated using the following assumptions:

Expected dividend yield			1.42	%
Expected volatility			36.3	%
Risk-free interest rate			4.65	%
Expected life (years)			6.5

The expected dividend yield is based on the average annual dividend yield as of the grant date. Expected volatility is based on the historical volatility of our stock and the implied volatility of our stock based on traded options. In calculating historical volatility, returns during calendar year 2002 were excluded as the extreme volatility during that time is not reasonably expected to be repeated in the future. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience.

     Cash received from stock option exercises was $15 million during the first six months of 2006.

Nonvested Deferred Shares

     Deferred shares are generally valued at market value on the grant date of the award and generally vest over three years. Deferred share expense, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.

     The following summary reflects nonvested deferred share activity and related information for the six-month period ended June 30, 2006.

						Weighted-
						Average
Deferred Shares		Shares				Fair Value*
		(Millions)
Nonvested at December 31, 2005			2.8			$	14.60
Granted			1.4			$	21.73
Forfeited			(.1	)		$	17.68
Vested			(.6	)		$	9.50
Nonvested at June 30, 2006			3.5			$	18.21

     The total market value of shares vested and issued during the first six months of 2006 was approximately $11.4 million.

     Performance-based share awards issued under the Plan represent 33 percent of nonvested deferred shares outstanding at June 30, 2006. These awards are generally earned at the end of a three-year period based on actual performance against a performance target. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original award amount.

Note 8. Inventories

     Inventories at June 30, 2006 and December 31, 2005 are:

		June 30,				December 31,
		2006				2005
		(Millions)
Natural gas in underground storage		$	135.7			$	90.4
Materials, supplies and other			86.1				82.2
Natural gas liquids			85.9				100.0
		$	307.7			$	272.6

Notes (Continued)

Note 9. Debt and Banking Arrangements

Long-Term Debt

   Revolving credit and letter of credit facilities (credit facilities)

     In May 2006, we obtained an unsecured, three-year, $1.5 billion revolving credit facility, replacing our $1.275 billion secured revolving credit facility. The new unsecured facility contains similar terms and financial covenants as the secured facility, but contains additional restrictions on asset sales, certain subsidiary debt and sale-leaseback transactions. The facility is guaranteed by Williams Gas Pipeline Company, LLC and we guarantee obligations of Williams Partner L.P. for up to $75 million. Northwest Pipeline Corporation (Northwest Pipeline) and Transco each have access to $400 million and Williams Partners L.P. has access to $75 million under the facility to the extent not otherwise utilized by us. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus an applicable margin. We are required to pay a commitment fee (currently .25 percent annually) based on the unused portion of the facility. The margins and commitment fee are based on the specific borrower’s senior unsecured long-term debt ratings. Significant financial covenants under the credit agreement include the following:

	•		Our ratio of debt to capitalization must be no greater than 65 percent;
	•		Ratio of debt to capitalization must be no greater than 55 percent for Northwest Pipeline and Transco;
	•		Our ratio of EBITDA to interest, on a rolling four quarter basis, must be no less than 2.5 for the period ending December 31, 2007 and 3.0 for the remaining term of the agreement.

     At June 30, 2006, no loans are outstanding under our credit facilities. Letters of credit issued under our facilities are:

		Letters of Credit at
		June 30, 2006
		(Millions)
$500 million unsecured credit facilities		$	411.6
$700 million unsecured credit facilities		$	439.1
$1.5 billion unsecured credit facility		$	107.1

   Issuances and retirements

     On May 28, 2003, we issued $300 million of 5.5 percent junior subordinated convertible debentures due 2033. These notes, which are callable after seven years, are convertible at the option of the holder into our common stock at a conversion price of approximately $10.89 per share. In November 2005, we initiated an offer to convert these debentures to shares of our common stock. In January 2006, we converted approximately $220.2 million of the debentures (see Note 10).

     In April 2006, Transco issued $200 million aggregate principal amount of 6.4 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement.

     In April 2006, we retired a secured floating-rate term loan for $488.9 million, including outstanding principal and accrued interest. The loan was due in 2008 and secured by substantially all of the assets of Williams Production RMT Company. The loan was retired using a combination of cash and revolving credit borrowings.

     In June 2006, Williams Partners L.P. completed its acquisition of 25.1 percent of our interest in Williams Four Corners LLC for $360 million. The acquisition was completed after successfully closing a $150 million private debt offering of 7.5 percent senior unsecured notes due 2011 and an equity offering of approximately $225 million in net proceeds. The debt and equity issued by Williams Partners L.P. is reported as a component of our consolidated debt balance and minority interest balance, respectively. Williams Four Corners LLC owns certain gathering, processing and treating assets in the San Juan Basin in Colorado and New Mexico.

     In June 2006, Northwest Pipeline issued $175 million aggregate principal amount of 7 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement.

Notes (Continued)

Note 10. Stockholders’ Equity

     In November 2005, we initiated an offer to convert our 5.5 percent junior subordinated convertible debentures into our common stock. In January 2006, we converted approximately $220.2 million of the debentures in exchange for 20.2 million shares of common stock, a $25.8 million cash premium, and $1.5 million of accrued interest.

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 of rulings in certain of these proceedings, a portion of the revenues of these subsidiaries has been collected subject to refund. The natural gas pipeline subsidiaries have accrued approximately $7 million for potential refunds as of June 30, 2006.

Issues Resulting From California Energy Crisis

     Subsidiaries of our Power segment are 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. Certain issues, however, 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 $30 million at June 30, 2006. 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 proceeding, 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. As part of the State Settlement, an additional $60 million, previously accrued, remains to be paid to the California Attorney General (or his designee) over the next four years, with the 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 Power have pled guilty to manipulation of gas prices through misreporting to an industry trade periodical. On February 21, 2006, we entered into a deferred prosecution agreement with the Department of Justice (DOJ) that is intended to resolve this matter. The agreement obligated us to pay a total of $50 million, of which $20 million was paid in March 2006. The remaining $30 million must be paid by March 2007. Absent a breach, the agreement will expire 15 months from the date of execution and no further action will be taken by the DOJ.

Notes (Continued)

     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:

	•		Federal court in New York based on an allegation of manipulation of the NYMEX gas market. We reached a settlement of this matter for $9.15 million which we paid into escrow in April 2006 subject to final court approval. The court issued a final approval of the settlement on May 24, 2006.
	•		Class action litigation in federal court in Nevada alleging that we manipulated gas prices for direct purchasers of gas in California. We have reached settlement of this matter for $2.4 million. Legal documents will be filed with the court and the settlement is subject to court approval.
	•		Class action litigation in state court in California alleging that we manipulated prices for indirect purchasers of gas in California. We have reached settlement of this matter for $15.6 million. Legal documents will be filed with the court and the settlement is subject to court approval.
	•		State court in California on behalf of certain individual gas users.
	•		Class action litigation in state court in Colorado, Kansas, and Tennessee brought on behalf of indirect purchasers of gas in those states.

It is reasonably possible that additional amounts may be necessary to resolve the remaining outstanding litigation in this area.

Mobile Bay Expansion

     In December 2002, an administrative law judge at the FERC issued an initial decision in Transco’s 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 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. Power 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, Power could have been subject to surcharges of approximately $86 million, excluding interest, through June 30, 2006, 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 has demanded repayment of the purchase price for the reduced portions of the claims. We have disputed the amount of the claim and are negotiating with the purchaser regarding potential payment 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, 2006, we had accrued

Notes (Continued)

liabilities of $14 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. Currently, Northwest Pipeline is assessing the actions needed for the sites to comply with Washington’s current environmental standards. At June 30, 2006, we have accrued liabilities totaling approximately $4 million for these costs. We expect that these costs will be recoverable through Northwest Pipeline’s rates.

     We also accrue environmental remediation costs for our natural gas gathering and processing facilities, primarily related to soil and groundwater contamination. At June 30, 2006, we have accrued liabilities totaling approximately $7 million for these costs.

     In August 2005, our subsidiary, Williams Production RMT Company, voluntarily disclosed to the Colorado Department of Public Health and Environment (CDPHE) two air permit violations. In October 2005, the CDPHE responded to our disclosure indicating that penalty immunity is not available in the matter and that it will seek resolution through a Compliance Order on Consent. We continue to believe that our voluntary self-evaluation and disclosure qualifies for penalty immunity. Negotiations with the CDPHE are ongoing.

     In March 2006, the CDPHE issued a notice of violation (NOV) to Williams Production RMT Company related to our operating permit for the Rulison oil separation and evaporation facility. On April 12, 2006, we met with the CDPHE to discuss the allegations contained in the NOV. In May 2006, we provided additional information to the agency regarding the emission estimates for operations from 1997 through 2003 and applied for updated permits.

     In July 2006, the CDPHE issued an NOV to Williams Production RMT Company related to operating permits for its Roan Cliffs and Hayburn Gas Plants in Garfield County, Colorado. We will meet with the CDPHE in August 2006 to discuss the allegations contained in the NOV.

     On July 2, 2001, the EPA issued an information request asking 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. On March 11, 2004, the DOJ invited the new owner of Williams Energy Partners, Magellan Midstream Partners, L.P. (Magellan), to enter into negotiations regarding alleged violations of the Clean Water Act and to sign a tolling agreement. No penalty has been assessed by the EPA; however, the DOJ stated in its letter that the maximum possible penalties were approximately $22 million for the alleged violations. It is anticipated that by providing additional clarification and through negotiations with the EPA and DOJ, that any proposed penalty will be reduced. All our environmental indemnity obligations to Magellan were released in a May 26, 2004 buyout. After previous negotiations with the DOJ related to four release events not related to Magellan-owned assets and a subsequent year-long absence of activity, in April 2006, the DOJ asked us to discuss the Magellan obligations and our obligations including two 2006 spills at our Colorado and Wyoming facilities. On July 18, 2006, Williams provided information as requested to the DOJ regarding the 2006 spills.

   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.

Notes (Continued)

   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, 2006, we have accrued liabilities of approximately $9 million for such excess costs.

     We were involved in a dispute with a defendant in two class action damages lawsuits in Florida state court involving this former chemical fertilizer business. Settlement of both class actions was judicially approved in October 2004. We were not a named defendant in the settled lawsuits, but have contractual obligations to participate with the named defendants in the ongoing environmental remediation. One defendant sought indemnification of approximately $20 million from us as a result of the settlement. In November 2005, the court ordered us to arbitrate the indemnification dispute with the one defendant. The hearing before the arbitrator occurred on June 26, 2006. On July 5, 2006, the arbitrator ruled in favor of the one defendant, awarding its full claim of approximately $20 million to be paid by us. As a result, we recorded a pre-tax charge of $19.2 million within discontinued operations in the second quarter of 2006.

   Other

     At June 30, 2006, we have accrued environmental liabilities totaling approximately $26 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;
	•		Discontinued petroleum refining facilities;
	•		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 had 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 2004, Williams Refining and the new owner of the Memphis refinery met with the EPA and the DOJ to discuss alleged violations and proposed penalties due to noncompliance issues identified in the report, including the benzene NESHAP issue. In July 2006, we finalized our agreements 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. The total settlement of approximately $3 million was fully accrued at June 30, 2006.

     In 2004, the Oklahoma Department of Environmental Quality (ODEQ) issued a NOV alleging various air permit violations associated with our operation of the Dry Trail gas processing plant prior to our sale of the facility. The NOV was issued to our subsidiary, Williams Field Services Company, and the purchaser of the plant. On April 14, 2005, the ODEQ issued a letter to the current Dry Trail plant owners assessing a penalty under the NOV of approximately $750,000. The current owner has asserted an indemnification claim to us for payment of the penalty. We and the current owner entered into an indemnity settlement under which we are responsible for payment of the penalty while the current owner is responsible for all forward costs of compliance. On June 6, 2006, we settled all issues with the ODEQ. The total settlement of approximately $249,000 was fully accrued at June 30, 2006.

     In 2004, our Gulf Liquids subsidiary initiated a self-audit of all environmental conditions (air, water, waste) at three facilities: 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). No specific penalty amount was assessed. Instead, LDEQ was required by Louisiana law to demand a profit and loss statement to determine the financial benefit obtained by noncompliance and to assess a penalty accordingly. Gulf Liquids offered $91,500 as a single, final,

Notes (Continued)

global multi-media settlement. Subsequent negotiations have resulted in a revised offer of $109,000, which LDEQ is currently reviewing.

     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.

Other Legal Matters

   Royalty indemnifications

     In 1996, a producer asserted a claim for damages against our Transco subsidiary for indemnification relating to prior royalty payments. The Louisiana Court of Appeals denied the producer’s appeal and affirmed a lower court’s judgment in favor of Transco. On March 31, 2006, the Louisiana Supreme Court denied the producer’s request for further review (see Note 3).

   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 on April 1, 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 and Texas Gas Transmission Corporation, 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 has 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 that it was declining to intervene in any of the Grynberg cases, including the action filed in federal court in Colorado against us. 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 remain 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. The District Court is considering whether to affirm or reject the special master’s recommendations and heard oral arguments on December 9, 2005.

     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

Notes (Continued)

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 allege that we and co-defendants, WilTel Communications (WilTel), previously an owned subsidiary known as Williams Communications, and certain corporate officers, have acted jointly and separately to inflate the stock price of both companies. Other suits allege similar causes of action related to a public offering in early January 2002 known as the FELINE PACS offering. These cases were also filed in 2002 against us, certain corporate officers, all members of our board of directors and all of the offerings’ underwriters. WilTel is no longer a defendant as a result of its bankruptcy. These cases have all been consolidated and an order has been 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 are currently covering 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 Power. On June 13, 2006, we announced that we had reached an agreement-in-principle to settle the claims of our securities holders for a total payment of $290 million. Of the total settlement amount, we expect to pay approximately $150 million in cash to fund the settlement, and expect the balance to be funded by our insurers. Payment will be made after the filing of definitive settlement documents with the court and the issuance of an order granting preliminary approval of the settlement. The exact amount of our payment is subject to final determination and timing of certain insurer coverage allocations. We have 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 as we believe the likelihood of any future performance is remote. As of June 30, 2006, we have accrued approximately $162 million for this settlement and related costs.

     Settlement discussions with the WilTel equity holders are ongoing, and the trial has been set to begin on January 17, 2007. Any obligation of ours to the WilTel equity holders as a result of a settlement or as a result of trial will not likely be covered by insurance, as we expect our insurance coverage to be fully utilized for the settlement described above.

     Derivative shareholder suits have been filed in state court in Oklahoma all based on similar allegations. The state court approved motions to consolidate and to stay these Oklahoma suits pending action by the federal court in the shareholder suits. On July 17, 2006, we reached an agreement-in-principle to settle the derivative suits. Under the terms of this settlement, we agreed to certain corporate governance and internal control enhancements, which have already been implemented, and to reimburse the plaintiffs’ attorney fees and expenses in an amount not to exceed $1.2 million which will be covered by insurance. The definitive settlement agreement will be subject to court approval.

   Federal income tax litigation

     One of our wholly-owned subsidiaries, Transco Coal Gas Company, is engaged in a dispute with the Internal Revenue Service (IRS) regarding the recapture of certain income tax credits associated with the construction of a coal gasification plant in North Dakota by Great Plains Gasification Associates, in which Transco Coal Gas Company was a partner. The IRS has taken alternative positions that allege a disposition date for purposes of tax credit recapture that is earlier than the position taken in the partnership tax return. On August 23, 2001, we filed a petition in the U.S. Tax Court to contest the adjustments to the partnership tax return proposed by the IRS. Certain settlement discussions have taken place since that date. During the fourth quarter of 2004, we determined that a reasonable settlement with the IRS could not be achieved. We filed a Motion for Summary Judgment with the Tax Court, which was heard, and denied, in January 2005. The matter was then tried before the Tax Court in February 2005. We continue to believe that the return position of the partnership is with merit. However, it is reasonably possible that the Tax Court could render an unfavorable decision that could ultimately result in estimated income taxes and interest of up to approximately $115 million in excess of the amount currently accrued.

Notes (Continued)

   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 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. On June 1, 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. Stays on those appeals have been lifted, and any appeals of the FERC’s Final Order must be filed by August 1, 2006.

     We expect that the Quality Bank Administrator will determine and invoice for amounts due based on the FERC Final Order during the fourth quarter 2006. At such time, we will be required to pay the invoiced amount, subject to any appeals of the FERC Final Order.

   Redondo Beach taxes

     On February 5, 2005, Power received a tax assessment letter, addressed to AES Redondo Beach, L.L.C. and Power, 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 and on September 23, 2005, the tax administrator for the city issued a decision in which he found Power jointly and severally liable with AES Redondo Beach for back taxes of approximately $36 million and interest and penalties of approximately $21 million. Both Power and AES Redondo Beach have filed notices of appeal that will be heard at the city level pursuant to a schedule that called for a final determination by May 19, 2006. While no final determination has been made to date, it is anticipated that Power and AES Redondo Beach will be required to pay the full amount of any final determination prior to further appeal to the California state courts.

     On December 19, 2005, Power received additional assessments from the city totaling approximately $3 million in taxes (inclusive of interest and penalties) for the period from October 1, 2004 through September 30, 2005. In late January, 2006, we received an additional assessment totaling approximately $270,000 (inclusive of interest and penalties) for the period from October 1, 2005 through December 31, 2005. Power and AES Redondo Beach have objected to these assessments and have requested a hearing on them. We believe that under Power’s 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 they do not agree. On April 24, 2006, Williams Power filed a motion to intervene in a refund action brought by AES Redondo in Los Angeles Superior Court related to certain taxes paid since the 2005 notice of assessment.

   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 Power to the suits as a third-party defendant. Gulf Liquids has 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

Notes (Continued)

to a sharing arrangement with XL Insurance Company. The contractors and sureties are asserting both contract and tort claims, some of which appear to be duplicative, against Gulf Liquids, Power, and others. The requested contractual and extra-contractual damages range from $20 million to $90 million. The cases filed in Harris County, Texas, have been consolidated.

     The jury returned its actual damages verdict against Power and Gulf Liquids on July 31, 2006 and its related punitive damages verdict on August 1, 2006. The court is not expected to enter any judgment until later in the third or fourth quarter of 2006. Based on our interpretation of the jury verdicts, we have estimated potential future exposure for actual damages of approximately $68 million plus potential interest of approximately $20 million, all of which have been accrued in second quarter 2006. In addition, it is reasonably possible that any ultimate judgment may include additional amounts in excess of our accrual totaling approximately $185 million which primarily represents our estimate of potential punitive damage exposure under Texas law.

   Hurricane lawsuits

     We were named as a defendant in two class action petitions for damages filed in the United States District Court for the Eastern District of Louisiana in September and October 2005 arising from hurricanes that struck Louisiana in 2005. The class plaintiffs, purporting to represent persons, businesses and entities in the State of Louisiana who have suffered damage as a result of the winds and storm surge from the hurricanes, allege that the operating activities of the two sub-classes of defendants, which are all oil and gas pipelines that dredged pipeline canals or installed pipelines in the marshes of south Louisiana (including Transco) and all oil and gas exploration and production companies which drilled for oil and gas or dredged canals in the marshes of south Louisiana, have altered marshland ecology and caused marshland destruction which otherwise would have averted all or almost all of the destruction and loss of life caused by the hurricanes. Plaintiffs request that the court allow the lawsuits to proceed as class actions and seek legal and equitable relief in an unspecified amount. On April 17, 2006, all defendants, including us, filed their joint motion to dismiss the class action petitions on various grounds.

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. At June 30, 2006, 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

     Power 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, 2006, Power’s estimated committed payments under these contracts range from approximately $215 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 $5.7 billion.

Notes (Continued)

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, Power, 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 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 $17 million on behalf of ACCROVEN. These expire in January 2007 and have no carrying value.

     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 $47 million at June 30, 2006. Our exposure declines systematically throughout the remaining term of WilTel’s obligations. The carrying value of these guarantees is approximately $42 million at June 30, 2006.

     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, 2006.

     Former managing directors of Gulf Liquids have been involved in litigation related to the construction of gas processing plants. Gulf Liquids has indemnity obligations to the former directors for legal fees and potential losses that might result from this litigation. Claims against these 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.

Notes (Continued)

Note 12. Comprehensive Income

     Comprehensive income is as follows:

		Three months ended								Six months ended
		June 30,								June 30,
		2006				2005				2006				2005
		(Millions)								(Millions)
Net income (loss)		$	(76.0	)		$	41.3			$	55.9			$	242.4
Other comprehensive income (loss):
Unrealized gains (losses) on derivative instruments			45.2				55.7				234.2				(272.9	)
Net reclassification into earnings of derivative instrument losses			32.9				54.7				134.3				122.5
Foreign currency translation adjustments			12.5				(2.9	)			10.3				(5.1	)
Minimum pension liability adjustment			—				—				(.3	)			—
Other comprehensive income (loss) before taxes			90.6				107.5				378.5				(155.5	)
Income tax (provision) benefit on other comprehensive income (loss)			(29.8	)			(42.3	)			(140.9	)			57.5
Other comprehensive income (loss)			60.8				65.2				237.6				(98.0	)
Comprehensive income (loss)		$	(15.2	)		$	106.5			$	293.5			$	144.4

     Unrealized gains (losses) 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, 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. Unrealized gains (losses) on derivative instruments for the three and six months ending June 30, 2006 and 2005 are primarily due to the effect of changes in the forward prices of these commodities relative to our hedge position.

     Our Midstream segment sells natural gas liquids produced by our processing plants. To reduce the exposure to changes in market prices, we enter into natural gas liquids swap agreements or forward contracts to fix the prices of 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

     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. Other primarily consists of corporate operations.

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 is done through intercompany derivatives with our Power segment which, in turn, enters into offsetting derivative contracts with unrelated third parties. Power bears the counterparty performance risks associated with unrelated third parties. External revenues of our Exploration & Production segment include third-party oil and gas sales, 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 &
		Production				Pipeline				Liquids				Power				Other				Eliminations				Total
		(Millions)
Three months ended June 30, 2006
Segment revenues:
External		$	(35.9	)		$	333.8			$	1,029.6			$	1,385.3			$	2.3			$	—			$	2,715.1
Internal			378.2				3.5				13.9				221.7				4.2				(621.5	)			—
Total revenues		$	342.3			$	337.3			$	1,043.5			$	1,607.0			$	6.5			$	(621.5	)		$	2,715.1
Segment profit (loss)		$	119.8			$	122.7			$	130.7			$	(79.6	)		$	(.7	)		$	—			$	292.9
Less:
Equity earnings			5.9				10.7				6.2				.3				—				—				23.1
Loss from investments			—				(.5	)			—				—				—				—				(.5	)
Segment operating income (loss)		$	113.9			$	112.5			$	124.5			$	(79.9	)		$	(.7	)		$	—				270.3
General corporate expenses																											(33.7	)
Securities litigation settlement and related costs																											(160.7	)
Consolidated operating income																										$	75.9
Three months ended June 30, 2005
Segment revenues:
External		$	(40.4	)		$	353.3			$	768.7			$	1,788.0			$	1.6			$	—			$	2,871.2
Internal			321.9				3.7				11.4				211.4				4.5				(552.9	)			—
Total revenues		$	281.5			$	357.0			$	780.1			$	1,999.4			$	6.1			$	(552.9	)		$	2,871.2
Segment profit (loss)		$	118.3			$	164.5			$	109.1			$	(75.0	)		$	(60.5	)		$	—			$	256.4
Less:
Equity earnings (losses)			3.6				7.9				4.1				.9				(6.7	)			—				9.8
Income (loss) from investments			—				—				.7				—				(49.1	)			—				(48.4	)
Segment operating income (loss)		$	114.7			$	156.6			$	104.3			$	(75.9	)		$	(4.7	)		$	—				295.0
General corporate expenses																											(35.5	)
Consolidated operating income																										$	259.5