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 September 30, 2005

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

For the transition period from ______ to ______

Commission file number 1-4174

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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes þ No 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 October 31 , 2005
Common Stock, $1 par value		573,014,682 Shares

 

 

The Williams Companies, Inc.
Index

		Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Operations — Three and Nine Months Ended September 30, 2005 and 2004			2
Consolidated Balance Sheet — September 30, 2005 and December 31, 2004			3
Consolidated Statement of Cash Flows — Nine Months Ended September 30, 2005 and 2004			4
Notes to Consolidated Financial Statements			5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			27
Item 3. Quantitative and Qualitative Disclosures about Market Risk			55
Item 4. Controls and Procedures			56
Part II. Other Information
Item 1. Legal Proceedings			57
Item 6. Exhibits			57
Computation of Ratio of Earnings to Fixed Charges
Certification of Chief Executive Officer Pursuant to Section 302
Certification of Chief Financial Officer Pursuant to Section 302
Certification of CEO and CFO Pursuant to Section 906

     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 words such as “anticipates,” “believes,” “expects,” “planned,” “scheduled,” “could,” “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 may cause future results to be materially different from the results 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 2004 Form 10-K.

The Williams Companies, Inc.

		Three months								Nine months
		ended September 30,								ended September 30,
(Dollars in millions, except per-share amounts)		2005				2004*				2005				2004*
Revenues:
Power		$	2,242.9			$	2,604.2			$	6,307.2			$	7,233.8
Gas Pipeline			345.8				321.0				1,038.1				1,011.0
Exploration & Production			318.4				209.3				848.9				563.5
Midstream Gas & Liquids			754.7				750.0				2,341.8				2,015.5
Other			6.3				6.7				19.4				26.3
Intercompany eliminations			(585.8	)			(516.0	)			(1,647.9	)			(1,353.0	)
Total revenues			3,082.3				3,375.2				8,907.5				9,497.1
Segment costs and expenses:
Costs and operating expenses			2,826.2				2,855.9				7,708.1				8,208.2
Selling, general and administrative expenses			90.6				89.4				226.8				257.7
Other (income) expense — net			(21.4	)			(5.7	)			(1.3	)			25.8
Total segment costs and expenses			2,895.4				2,939.6				7,933.6				8,491.7
General corporate expenses			42.8				24.1				106.3				84.5
Operating income (loss):
Power			(227.4	)			124.2				(190.3	)			137.3
Gas Pipeline			144.1				137.4				456.7				409.6
Exploration & Production			153.0				67.5				367.9				156.2
Midstream Gas & Liquids			117.9				104.0				343.7				305.2
Other			(0.7	)			2.5				(4.1	)			(2.9	)
General corporate expenses			(42.8	)			(24.1	)			(106.3	)			(84.5	)
Total operating income			144.1				411.5				867.6				920.9
Interest accrued			(166.0	)			(197.3	)			(495.3	)			(662.9	)
Interest capitalized			1.8				1.0				4.3				5.7
Interest rate swap loss			—				(4.0	)			—				(5.3	)
Investing income			31.1				9.2				44.9				31.2
Early debt retirement costs			—				(155.1	)			—				(252.4	)
Minority interest in income of consolidated subsidiaries			(6.8	)			(5.2	)			(16.8	)			(16.0	)
Other income (expense) — net			(1.1	)			4.7				12.5				19.6
Income from continuing operations before income taxes			3.1				64.8				417.2				40.8
Provision (benefit) for income taxes			(2.6	)			48.6				168.6				43.1
Income (loss) from continuing operations			5.7				16.2				248.6				(2.3	)
Income (loss) from discontinued operations			(1.3	)			82.4				(1.8	)			92.6
Net income		$	4.4			$	98.6			$	246.8			$	90.3
Basic earnings (loss) per common share:
Income (loss) from continuing operations		$	.01			$	.03			$	.43			$	(.01	)
Income (loss) from discontinued operations			—				.16				—				.18
Net income		$	.01			$	.19			$	.43			$	.17
Weighted-average shares (thousands)			572,543				523,111				569,426				521,438
Diluted earnings (loss) per common share:
Income (loss) from continuing operations		$	.01			$	.03			$	.42			$	(.01	)
Income (loss) from discontinued operations			—				.16				—				.18
Net income		$	.01			$	.19			$	.42			$	.17
Weighted-average shares (thousands)			580,735				529,525				604,749				521,438
Cash dividends per common share		$	.075			$	.01			$	.175			$	.03

See accompanying notes.

The Williams Companies, Inc.

		September 30,				December 31,
(Dollars in millions, except per-share amounts)		2005				2004*
ASSETS
Current assets:
Cash and cash equivalents		$	1,360.5			$	930.0
Restricted cash			48.4				77.4
Accounts and notes receivable less allowance of $96.4 ($98.8 in 2004)			1,490.1				1,422.8
Inventories			302.8				261.1
Derivative assets			8,636.5				2,961.0
Margin deposits			457.1				131.7
Assets of discontinued operations			12.8				13.6
Deferred income taxes			146.3				89.0
Other current assets and deferred charges			174.3				157.0
Total current assets			12,628.8				6,043.6
Restricted cash			36.4				35.3
Investments			1,278.6				1,316.2
Property, plant and equipment, at cost			17,191.3				16,452.8
Less accumulated depreciation, depletion, and amortization			(4,988.3	)			(4,566.0	)
Property, plant and equipment — net			12,203.0				11,886.8
Derivative assets			5,776.2				3,025.3
Goodwill			1,014.5				1,014.5
Other assets and deferred charges			718.3				671.3
Total assets		$	33,655.8			$	23,993.0
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	1,217.0			$	1,043.2
Accrued liabilities			1,065.0				974.0
Customer margin deposits payable			404.1				17.7
Liabilities of discontinued operations			1.3				1.6
Derivative liabilities			9,024.5				2,859.3
Long-term debt due within one year			122.4				250.1
Total current liabilities			11,834.3				5,145.9
Long-term debt			7,598.7				7,711.9
Deferred income taxes			2,268.4				2,470.1
Derivative liabilities			5,676.2				2,735.7
Other liabilities and deferred income			917.7				873.8
Contingent liabilities and commitments (Note 12)
Minority interests in consolidated subsidiaries			206.1				99.7
Stockholders’ equity:
Common stock, $1 per share par value, 960 million shares authorized, 578.6 million issued in 2005, 563.8 million issued in 2004			578.6				563.8
Capital in excess of par value			6,317.7				6,005.9
Accumulated deficit			(1,159.7	)			(1,306.5	)
Accumulated other comprehensive loss			(527.4	)			(244.2	)
Other			(13.6	)			(21.9	)
			5,195.6				4,997.1
Less treasury stock (at cost), 5.7 million shares of common stock in 2005 and 2004			(41.2	)			(41.2	)
Total stockholders’ equity			5,154.4				4,955.9
Total liabilities and stockholders’ equity		$	33,655.8			$	23,993.0

See accompanying notes.

The Williams Companies, Inc.

		Nine months ended September 30,
		2005				2004*
		(Millions)
OPERATING ACTIVITIES:
Income (loss) from continuing operations		$	248.6			$	(2.3	)
Adjustments to reconcile to cash provided by operations:
Depreciation, depletion and amortization			545.9				495.4
Provision (benefit) for deferred income taxes			(63.1	)			30.6
Provision for loss on investments, property and other assets			56.3				55.5
Net gain on disposition of assets			(47.0	)			(4.5	)
Early debt retirement costs			—				252.4
Minority interest in income of consolidated subsidiaries			16.8				16.0
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable			(115.0	)			341.0
Inventories			(39.9	)			(18.8	)
Margin deposits and customer margin deposits payable			61.0				393.6
Other current assets and deferred charges			(2.2	)			87.3
Accounts payable			114.5				(232.0	)
Accrued liabilities			52.7				(287.8	)
Changes in current and noncurrent derivative assets and liabilities			203.1				(128.4	)
Changes in noncurrent restricted cash			—				86.5
Other, including changes in noncurrent assets and liabilities			50.6				(14.9	)
Net cash provided by operating activities of continuing operations			1,082.3				1,069.6
Net cash provided by operating activities of discontinued operations			—				18.6
Net cash provided by operating activities			1,082.3				1,088.2
FINANCING ACTIVITIES:
Payments of long-term debt			(243.6	)			(3,032.8	)
Payments of notes payable			—				(3.3	)
Proceeds from issuance of common stock			303.4				14.7
Proceeds from sale of limited partner units of consolidated partnership			111.0				—
Dividends paid			(100.0	)			(15.6	)
Payments of debt issuance costs and amendment fees			(29.6	)			(25.7	)
Premiums paid on tender offer and early debt retirement			—				(214.0	)
Dividends paid to minority interests			(19.8	)			(5.9	)
Changes in restricted cash			37.1				41.6
Changes in cash overdrafts			58.7				(27.4	)
Other — net			.1				(5.5	)
Net cash provided (used) by financing activities of continuing operations			117.3				(3,273.9	)
Net cash used by financing activities of discontinued operations			—				(1.2	)
Net cash provided (used) by financing activities			117.3				(3,275.1	)
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures			(885.9	)			(538.5	)
Proceeds from dispositions			39.0				7.7
Contract termination payment			87.9				—
Purchases of investments/advances to affiliates			(98.2	)			(1.6	)
Purchases of auction rate securities			(171.3	)			—
Purchases of restricted investments			—				(471.8	)
Proceeds from sales of businesses			31.4				850.1
Proceeds from sales of auction rate securities			115.2				—
Proceeds from sale of restricted investments			—				851.4
Proceeds received on sale of note from WilTel			54.7				—
Payments received on notes receivable from WilTel			—				68.6
Proceeds from dispositions of investments and other assets			51.6				86.3
Other — net			6.5				(6.0	)
Net cash provided (used) by investing activities of continuing operations			(769.1	)			846.2
Net cash used by investing activities of discontinued operations			—				(.8	)
Net cash provided (used) by investing activities			(769.1	)			845.4
Increase (decrease) in cash and cash equivalents			430.5				(1,341.5	)
Cash and cash equivalents at beginning of period			930.0				2,318.2
Cash and cash equivalents at end of period		$	1,360.5			$	976.7

See accompanying notes.

The Williams Companies, Inc.

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 September 30, 2005, and results of operations for the three and nine months ended September 30, 2005 and 2004 and cash flows for the nine months ended September 30, 2005 and 2004.

     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.

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, financial position and cash flows of the following components as discontinued operations (see Note 5):

	•		refining, retail and pipeline operations in Alaska, part of the previously reported Petroleum Services segment; and
	•		our straddle plants in western Canada, previously part of the Midstream Gas & Liquids (Midstream) segment.

     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, consistent with the presentation in our 2004 Form 10-K. In addition, certain other amounts have been reclassified to conform to the current classification.

     During fourth-quarter 2004, we reclassified the operations of Gulf Liquids New River Project L.L.C. (Gulf Liquids) to continuing operations within our Midstream segment in accordance with Emerging Issues Task Force (EITF) Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations’’ (EITF 03-13), which was issued in the fourth quarter of 2004. Under the provisions of EITF 03-13, Gulf Liquids activities no longer qualified for reporting as discontinued operations based on management’s expectation that we will continue to have significant commercial activity with the disposed entity. The operations of Gulf Liquids were reclassified to continuing operations within our Midstream segment. All periods presented reflect this reclassification.

     At December 31, 2004, all of the assets and liabilities of Gulf Liquids, which are not material to our Consolidated Balance Sheet, were classified as held for sale and included in Other current assets and deferred charges and Accrued liabilities. During second-quarter 2005, we decided to retain a portion of the Gulf Liquids operations and reclassified certain of the assets and liabilities from held for sale to held for use. The sale of the remaining assets held for sale closed on July 15, 2005.

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

Notes (Continued)

3. Asset sales, impairments and other accruals

     Significant gains or losses from asset sales, impairments and other accruals included in Other (income) expense — net within Segment costs and expenses and Investing income are included in the following tables.

		Three months ended								Nine months ended
		September 30,								September 30,
		2005				2004				2005				2004
		(Millions)								(Millions)
Other (income) expense — net:
Power
Accrual for litigation contingencies		$	0.4			$	—			$	13.5			$	—
Gas Pipeline
Write-off of previously-capitalized costs			—				—				—				9.0
Exploration & Production
Gain on sale of certain natural gas properties			(21.7	)			—				(29.6	)			—
Loss provision related to an ownership dispute			—				—				—				11.3

		Three months ended								Nine months ended
		September 30,								September 30,
		2005				2004				2005				2004
		(Millions)								(Millions)
Investing income:
Midstream Gas & Liquids
Gain on sale of remaining interests in Mid-America Pipeline (MAPL) and Seminole Pipeline (Seminole)		$	—			$	—			$	8.6			$	—
Other
Impairment of investment in Longhorn Partners Pipeline L.P. (Longhorn)			—				—				(49.1	)			(10.8	)
Net unreimbursed Longhorn recapitalization advisory fees			—				—				—				(6.5	)
Impairment of cost-based international investments			—				(15.7	)			—				(15.7	)

     The impairments of the investment in Longhorn reflect a reduction of carrying value to management’s estimate of fair market value, following a determination that there was an other-than-temporary decline in value. During second-quarter 2005, Longhorn’s management determined that continued operation as originally planned was no longer feasible. Based on that assessment, we recorded an impairment of $49.1 million. The remaining net book value of our investment in Longhorn is $42 million at September 30, 2005. We will continue to consider various strategic scenarios and reassess our estimate of fair value in Longhorn following management’s finalization of a strategic alternative to the current operating plan, which may result in a significant additional impairment in a future period. We expect a decision on the future operation of Longhorn by the end of 2005.

     To ensure adequate liquidity to continue operations while assessing alternatives, Longhorn has obtained a $25 million bridge loan commitment from existing investors, which is secured by a first lien on the assets of Longhorn. We have committed to fund up to $10 million of this loan, which has a one-year term and an interest rate of 14 percent. As of September 30, 2005, the balance of our loan to Longhorn under this arrangement is approximately $4.8 million and is included in Other current assets and deferred charges. The loan agreement allows for an additional $25 million loan, secured by the same first lien on the assets of Longhorn. All existing investors will have the opportunity to participate in funding the second $25 million increment. Levels of participation and the interest rate for this second increment will be determined through an auction process. This loan was contemplated in the impairment analysis performed in the second quarter of 2005 and thus does not result in an additional impairment.

     Costs and operating expenses includes income from a liability reversal of $14.2 million in our Gas Pipeline segment associated with a favorable rate case ruling involving adjustments to estimated gas purchase costs for operations in prior periods.

     General corporate expenses includes $13.8 million of expense in our Other segment related to the settlement of certain insurance coverage issues with an insurer that had underwritten portions of the fiduciary insurance applicable to our pending ERISA litigation and the directors and officers insurance applicable to our pending securities litigation.

Notes (Continued)

4. Provision (benefit) for income taxes

     The provision (benefit) for income taxes from continuing operations includes:

		Three months ended								Nine months ended
		September 30,								September 30,
		2005				2004				2005				2004
		(Millions)								(Millions)
Current:
Federal		$	205.6			$	(3.2	)		$	212.9			$	—
State			(1.3	)			1.2				6.7				5.6
Foreign			5.8				1.1				12.1				6.9
			210.1				(.9	)			231.7				12.5
Deferred:
Federal			(212.6	)			24.4				(73.5	)			11.3
State			(1.3	)			23.1				14.8				12.7
Foreign			1.2				2.0				(4.4	)			6.6
			(212.7	)			49.5				(63.1	)			30.6
Total provision (benefit)		$	(2.6	)		$	48.6			$	168.6			$	43.1

     The effective income tax rate benefit for the three months ended September 30, 2005, is less than the federal statutory rate due primarily to the effect of income tax settlements (including a reduction of an accrual for income tax contingencies) and net foreign operations, partially offset by state income taxes and an increase in valuation allowance. The significant current federal provision and deferred federal benefit are primarily the result of income tax settlements in the third quarter.

     The effective income tax rate for the nine months ended September 30, 2005, is greater than the federal statutory rate due primarily to the effect of state income taxes, an increase in valuation allowance and nondeductible expenses, partially offset by income tax settlements (including a reduction of an accrual for income tax contingencies) and net foreign operations.

     The effective income tax rate for the three months ended September 30, 2004, is greater than the federal statutory rate due primarily to the effect of state income taxes, net foreign operations and nondeductible expenses.

     The effective income tax rate for the nine months ended September 30, 2004, is greater than the federal statutory rate due primarily to the effect of state income taxes, net foreign operations, nondeductible expenses and an accrual for income tax contingencies.

5. Discontinued operations

     The businesses discussed below represent components that have been sold or approved for sale by our Board of Directors as of September 30, 2005, and also meet all requirements to be treated as discontinued operations. Therefore, their results of operations (including any impairments, gains or losses), financial position and cash flows have been reflected in the consolidated financial statements and notes as discontinued operations.

     Discontinued operations did not generate any revenues for the three and nine months ended September 30, 2005. Discontinued operations included revenues of $21.4 million for the three months ended September 30, 2004, and $353.4 million for the nine months ended September 30, 2004.

2004 completed transactions

Canadian straddle plants

     During the third quarter of 2004, we completed the sale of the Canadian straddle plants for approximately $544 million and recognized a $189.8 million pre-tax gain on the sale. The operations were part of the Midstream segment.

Notes (Continued)

Alaska refining, retail and pipeline operations

     On March 31, 2004, we completed the sale of our Alaska refinery, retail and pipeline operations for approximately $304 million. We received $279 million in cash at the time of the sale and $25 million in cash during the second quarter of 2004. We recognized a $3.6 million pre-tax gain on the sale during first-quarter 2004. These operations were part of the previously reported Petroleum Services segment.

     Discontinued operations included charges of $134.4 million for the three months ended September 30, 2004, and $151.8 million for the nine months ended September 30, 2004, associated with certain Quality Bank litigation matters (see Note 12).

6. Earnings (loss) per common share from continuing operations

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

		Three months ended								Nine months ended
		September 30,								September 30,
		2005				2004				2005				2004
		(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)		$	5.7			$	16.2			$	248.6			$	(2.3	)
Basic weighted-average shares (2)			572,543				523,111				569,426				521,438
Effect of dilutive securities:
Unvested deferred shares (3)			2,999				2,698				2,849				—
Stock options			5,193				3,716				4,926				—
Convertible debentures			—				—				27,548				—
Diluted weighted-average shares			580,735				529,525				604,749				521,438
Earnings (loss) per common share from continuing operations:
Basic		$	.01			$	.03			$	.43			$	(.01	)
Diluted		$	.01			$	.03			$	.42			$	(.01	)

     For the nine months ended September 30, 2004, approximately 2.7 million weighted-average unvested deferred shares and 3.7 million weighted-average stock options have been excluded from the computation of Diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations.

     For the three months ended September 30, 2005, and the three and nine months ended September 30, 2004, approximately 27.5 million weighted-average shares related to the assumed conversion of convertible debentures, as well as the related interest, net of tax, have been excluded from the computation of Diluted earnings per common share. Inclusion of these shares would have been antidilutive. If no other components used to calculate Diluted earnings per common share change, we estimate the assumed conversion of the convertible debentures would become dilutive and therefore be included in Diluted earnings (loss) per common share at an Income from continuing operations available to common stockholders amount of $53.7 million for the three months ended September 30, 2005, and $49 million and $146.4 million for the three and nine months ended September 30, 2004, respectively.

Notes (Continued)

     The table below includes information related to options that were outstanding at September 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 third-quarter weighted-average market price of our common shares.

		2005				2004
Options excluded (millions)			4.8				9.3
Weighted-average exercise prices of options excluded		$	35.23			$	27.44
Exercise price range of options excluded		$	23.88-$42.29			$	12.22-$42.29
Third-quarter weighted-average market price		$	21.75			$	11.97

7. Employee benefit plans

     Net periodic pension (income) expense and other postretirement benefit expense for the three and nine months ended September 30, 2005 and 2004 are as follows:

		Pension Benefits
		Three months								Nine months
		ended September 30,								ended September 30,
		2005				2004				2005				2004
		(Millions)								(Millions)
Components of net periodic pension (income) expense:
Service cost		$	5.4			$	6.0			$	16.2			$	18.1
Interest cost			12.0				12.7				35.8				37.9
Expected return on plan assets			(17.8	)			(16.3	)			(53.3	)			(48.7	)
Amortization of prior service cost (credit)			(.1	)			(.3	)			(.3	)			(1.1	)
Recognized net actuarial (gain) loss			1.7				2.4				(8.3	)			7.0
Regulatory asset amortization			.7				.5				.3				1.5
Settlement/curtailment expense			.1				—				2.7				.1
Net periodic pension (income) expense		$	2.0			$	5.0			$	(6.9	)		$	14.8

		Other Postretirement Benefits
		Three months								Nine months
		ended September 30,								ended September 30,
		2005				2004				2005				2004
		(Millions)								(Millions)
Components of net periodic other postretirement benefit expense:
Service cost		$	.8			$	.6			$	2.3			$	2.4
Interest cost			5.8				3.3				14.6				14.1
Expected return on plan assets			(2.9	)			(3.1	)			(8.6	)			(9.3	)
Amortization of transition obligation			—				.7				—				2.0
Amortization of prior service cost (credit)			(.1	)			.2				(4.2	)			.5
Recognized net actuarial loss			.9				—				2.4				—
Regulatory asset amortization			1.5				1.5				5.3				5.0
Net periodic other postretirement benefit expense		$	6.0			$	3.2			$	11.8			$	14.7

     Net periodic pension (income) expense for the nine months ended September 30, 2005, includes a $17.1 million reduction to expense to record the cumulative impact of a correction of an error determined from 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.

     As of September 30, 2005, we have contributed $30.3 million to our pension plans and $11.5 million to our other postretirement benefit plans. We presently anticipate contributing approximately $10 million more to our pension plans in 2005 for a total of approximately $40 million. We presently anticipate contributing approximately $4 million more to our other postretirement benefit plans in 2005 for a total of approximately $15 million.

     In December 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) beginning in 2006 as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Our health care plans for retirees include prescription drug coverage. We

Notes (Continued)

amended our health care plans for retirees in the fourth quarter of 2004 to coordinate and pay secondary to any part of Medicare, including prescription drug benefits covered by Medicare Part D. As a result of the amendment, our plans were not actuarially equivalent to Medicare Part D. The amendment decreased our benefit obligation by $75.5 million in 2004. The net reduction to the obligation is being amortized over approximately seven years which is the participants’ average remaining years of service to full eligibility for benefits beginning in 2005 and is reflected in the amortization of prior service credit for other postretirement benefits in the previous table for the nine months ended September 30, 2005.

     Due to anticipated difficulties to administer our plans as previously amended to coordinate and pay secondary to Medicare Part D in 2006, we amended our plans in June 2005 to provide primary prescription drug coverage and apply for the federal subsidy in 2006. As a result of the amendment, our plans are actuarially equivalent to Medicare Part D. The amendment increased our benefit obligation by $51.2 million at June 30, 2005. The increase to the obligation is being amortized over the participants’ average remaining years of service to full eligibility for benefits, which is approximately seven years, beginning in the third quarter of 2005. Net periodic other postretirement benefit expense for the three and nine months ended September 30, 2005, reflects an increase of $3.6 million, including an increase in recognized net actuarial loss of $.2 million, an increase in service cost of $.2 million, an increase in interest cost of $1.3 million and an increase in amortization of prior service credit of $1.9 million, resulting from the plan amendment. We are continuing to evaluate coordination with Medicare Part D as a strategy to decrease our benefit obligation in the future and will closely monitor the development of systems and capabilities of third-party administrators to coordinate prescription drug benefits with the Centers for Medicare & Medicaid Services.

8. Stock-based compensation

     Employee stock-based awards are accounted for under Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Fixed-plan common stock options generally do not result in compensation expense because the exercise price of the stock option equals the market price of the underlying stock on the date of grant. The following table illustrates the effect on Net income and earnings per common share for the three and nine months ended September 30, 2005 and 2004 if we had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation.” We currently calculate fair value using the Black-Scholes pricing model.

		Three months ended								Nine months ended
		September 30,								September 30,
		2005				2004				2005				2004
		(Millions, except per share amount)
Net income, as reported		$	4.4			$	98.6			$	246.8			$	90.3
Add: Stock-based employee compensation expense included in the Consolidated Statement of Operations, net of related tax effects			2.8				2.3				6.8				8.1
Deduct: Stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects			(4.8	)			(9.7	)			(12.8	)			(20.3	)
Pro forma net income		$	2.4			$	91.2			$	240.8			$	78.1
Earnings per share:
Basic — as reported		$	.01			$	.19			$	.43			$	.17
Basic — pro forma		$	—			$	.17			$	.42			$	.15
Diluted — as reported		$	.01			$	.19			$	.42			$	.17
Diluted — pro forma		$	—			$	.17			$	.41			$	.15

     Since compensation expense for stock options is recognized over the future years’ vesting period for pro forma disclosure purposes and additional awards are generally made each year, pro forma amounts may not be representative of future years’ amounts.

Notes (Continued)

9. Inventories

     Inventories at September 30, 2005 and December 31, 2004 are as follows:

		September 30,				December 31,
		2005				2004
		(Millions)
Natural gas liquids		$	89.2			$	63.2
Natural gas in underground storage			136.4				133.1
Materials, supplies and other			77.2				64.8
		$	302.8			$	261.1

10. Debt and banking arrangements

Revolving credit and letter of credit facilities

     In January 2005, we terminated our two existing unsecured bank revolving credit facilities totaling $500 million and replaced them with two new facilities. The new credit facilities contain the same terms as the previous credit agreements, but almost all of the restrictive covenants and events of default were removed or made less restrictive. As a result of the termination and replacement, we paid $17.9 million in fees, which are being amortized over the life of the new facilities. At September 30, 2005, letters of credit totaling $435 million have been issued under these facilities and no revolving credit loans are outstanding.

     In September 2005, we entered into two unsecured bank revolving credit facilities totaling $700 million. These facilities are similar in structure to our existing unsecured revolving credit facilities described above. These facilities provide for both borrowings and issuing letters of credit, but are expected to be used primarily for issuing letters of credit. We are required to pay fixed facility fees at a weighted-average rate of 2.29 percent on the total committed amount of the facilities. In addition, we will pay interest on any borrowings at a fluctuating rate comprised of either a base rate or LIBOR. Similar to our existing unsecured revolving credit facilities, the funding bank syndicated its associated credit risk into the institutional investor market via a private offering, which allows for the resale of certain restricted securities to qualified institutional buyers. To facilitate the syndication of these facilities, the bank established trusts funded by the institutional investors. The assets of the trusts serve as collateral to reimburse the bank for our borrowings in the event the facilities are delivered to the investors. Thus, we have no asset securitization or collateral requirements under the new facilities. Upon the occurrence of certain credit events, letters of credit under the agreement become cash collateralized creating a borrowing under the facilities. Concurrently, the funding bank can deliver the facilities to the institutional investors, whereby the investors replace the funding bank as lender under the facilities. Upon such occurrence, we will pay:

	•		a fixed facility fee as described above,
	•		interest on borrowings under the $500 million facility at a fixed rate of 4.35 percent, and
	•		interest on borrowings under the $200 million facility at a floating LIBOR interest rate.

At September 30, 2005, letters of credit totaling $559 million have been issued under these facilities and no revolving credit loans are outstanding.

     During May 2005, we amended and restated our $1.275 billion secured revolving credit facility resulting in certain changes, including the following:

	•		added Williams Partners L.P. as a borrower for up to $75 million;
	•		provided our guarantee for the obligations of Williams Partners L.P. under this agreement;
	•		released certain Midstream assets held as collateral and replaced them with the common stock of Transco; and
	•		reduced commitment fees and margins.

At September 30, 2005, letters of credit totaling $713 million have been issued under this facility and no revolving credit loans are outstanding.

Notes (Continued)

Retirements

     During January 2005, we retired $200 million of 6.125 percent notes issued January 15, 1998, by Transco, which matured January 15, 2005.

11. Stockholders’ equity

     In January 2002, we issued $1.1 billion of 6.5 percent notes payable in 2007 that were subject to remarketing in 2004. Each note was bundled with an equity forward contract (together, the FELINE PACS units) and sold in a public offering for $25 per unit. The equity forward contract required the holder of each note to purchase one share of our common stock for $25 three years from issuance of the contract. In the fourth quarter of 2004, we exchanged approximately 33.1 million of the 44 million issued and outstanding FELINE PACS units for one share of our common stock plus $1.47 in cash for each unit. On the February 16, 2005, settlement date of the equity forward contracts, the holders of the remaining 10.9 million equity forward contracts purchased one share of our common stock for $25, resulting in cash proceeds of approximately $273 million and an increase in Capital in excess of par value of approximately $262 million.

12. 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 $5 million for potential refund as of September 30, 2005.

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 have been challenged in various proceedings, including those before the Federal Energy Regulatory Commission (FERC). These challenges include 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 have substantially resolved each of these issues with these parties. Certain issues, however, remain open at the FERC and for other non-settling parties, such as the United States Department of Justice (DOJ).

Refund proceedings

     Although we have entered into the State Settlement and Utilities Settlement, which resolve the refund issues among the settling parties, we have potential refund exposure to non-settling parties, such as various California end users that did not agree to opt into 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 non-settling 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 $27 million at September 30, 2005. 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, are now pending at the Ninth Circuit Court of Appeals.

Notes (Continued)

Summer 2002 90-day contracts

     On May 2, 2002, PacifiCorp filed a complaint against us with the FERC seeking relief from rates contained in three separate confirmation agreements between PacifiCorp and Power (known as the Summer 2002 90-day contracts). PacifiCorp filed similar complaints against three other suppliers. PacifiCorp alleged that the rates contained in the contracts are unjust and unreasonable. On August 8, 2005, the Ninth Circuit Court of Appeals upheld the FERC’s order that affirmed the administrative law judge’s initial decision dismissing the complaints. On September 22, 2005, PacifiCorp submitted a rehearing petition that seeks to overturn the decision that dismissed the appeal.

Investigations of alleged market manipulation

     As a result of various allegations and FERC orders, in 2002 the FERC initiated investigations of manipulation of the California gas and power markets. As they related to us, these investigations included economic and physical withholding, so-called “Enron Gaming Practices” and gas index manipulation. Each of these FERC investigations of alleged market manipulation was resolved pursuant to the Utilities Settlement that is discussed above in Refund proceedings.

     As also discussed below in Reporting of natural gas-related information to trade publications, on November 8, 2002, we received a subpoena from a federal grand jury in northern California seeking documents related to our involvement in California markets. We have completed our response to the subpoena. This subpoena is a part of the broad DOJ investigation regarding gas and power trading.

Long-term contracts

     In February 2001, during the height of the California energy crisis, we entered into a long-term power contract with the State of California to assist in stabilizing its market. The State of California later sought to rescind this contract. Following settlement discussions between the State and us on the contract issue as well as other state initiated proceedings and allegations of market manipulation, we entered into the State Settlement that includes renegotiated long-term energy contracts. These contracts are made up of block energy sales, dispatchable products and a gas contract. The State Settlement does not extend to criminal matters or matters of willful fraud, but did resolve civil complaints brought by the California Attorney General against us and the State of California’s refund claims that are discussed above. In addition, the State Settlement resolved ongoing investigations by the States of California, Oregon and Washington. Certain private class action and other civil plaintiffs who have initiated class action litigation against us and others in California based on allegations against us with respect to the California energy crisis also executed the State Settlement. On June 29, 2004, the court approved the State Settlement, making it effective as to plaintiffs and terminating the class actions as to us. A limited group did opt out of the State Settlement. Litigation by non-California plaintiffs, or relating to reporting of natural gas information to trade publications, as discussed below, will continue. As of September 30, 2005, pursuant to the terms of the State Settlement, we have transferred ownership of six gas powered electric turbines, have made three payments totaling $87 million to the California Attorney General, and have funded a $15 million fee and expense fund associated with civil actions that are subject to the State Settlement. An additional $60 million, previously accrued, remains to be paid to the California Attorney General (or his designee) over the next five 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. As noted above, on November 8, 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. Two former traders with Power have pled guilty to manipulation of gas prices through misreporting to an industry trade periodical. The DOJ’s investigation of us in this matter is continuing, and we are discussing the disposition of this matter with the DOJ. If we are unable to reach a consensual disposition with the DOJ, it is also possible that we could be indicted by the DOJ for alleged violations of the Commodity Exchange Act. In addition, the Commodity Futures Trading Commission (CFTC) has conducted an investigation of us regarding this issue. On July 29, 2003, we reached a settlement with the CFTC in which, in exchange for $20 million, the CFTC closed its investigation, and we did not admit or deny allegations that we had engaged in false reporting or attempted manipulation. Civil suits based on allegations of manipulating the gas indices have been brought against

Notes (Continued)

us and others. We are currently a defendant in federal court in New York based on an allegation of manipulation of the NYMEX gas market. We are also a defendant in class actions in federal court in Nevada alleging that we manipulated gas prices for direct purchasers of gas in California and in state court in California alleging that we manipulated prices for indirect purchasers of gas in California. Separate cases have also been filed against us in California on behalf of certain individual gas users. We are also a defendant in class action litigation in Kansas and Tennessee brought on behalf of indirect purchasers of gas in those states. Each of these cases is in the early stages of discovery. Settlement discussions regarding certain of these matters have occurred. For the collective proceedings involving this matter and based on discussions to date with respective parties, we believe it is reasonably possible that penalties or settlements could result in a range of exposure estimated to be $60 million to $75 million in addition to amounts accrued at September 30, 2005.

Investigations related to natural gas storage inventory

     We responded to a subpoena from the CFTC and inquiries from the FERC related to investigations involving natural gas storage inventory issues. Through some of our subsidiaries, we own and operate natural gas storage facilities. On August 30, 2004, the CFTC announced that it had concluded its investigation. The FERC inquiries related to the sharing of non-public data concerning inventory levels and the potential uses of such data in natural gas trading. On June 15, 2005, the FERC approved a settlement in which we paid refunds and a penalty totaling $7.6 million.

Mobile Bay expansion

     On December 3, 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. The administrative law judge’s initial decision is subject to review by the FERC. On March 26, 2004, the FERC issued an Order on Initial Decision in which it reversed certain parts of the administrative law judge’s holding 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 $73 million, excluding interest, through September 30, 2005, in addition to increased costs going forward. On April 26, 2004, several parties, including Transco, filed requests for rehearing of the FERC’s March 26, 2004 order. On August 5, 2005, the FERC issued an order denying the rehearing requests challenging the FERC’s acceptance of Transco’s proposal for rolled-in rates. Certain parties have filed appeals in federal court seeking to have the FERC’s ruling on this issue overturned.

Enron bankruptcy

     We have outstanding claims against Enron Corp. and various of its subsidiaries (collectively “Enron”) related to Enron’s bankruptcy filed in December 2001. In March 2002, we sold $100 million of our claims against Enron to a third party for $24.5 million. On December 23, 2003, Enron filed objections to these claims. Under the sales agreement, the purchaser of the claims may demand repayment of the purchase price, plus interest assessed at an annual rate of 7.5 percent, for that portion of the claims still subject to objections beginning 90 days following the initial objection. To date, the purchaser has not demanded repayment.

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 September 30, 2005, Transco had

Notes (Continued)

accrued liabilities of $21 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, Transco has estimated its aggregate exposure for remediation of these sites to be less than $500,000, which is included in the environmental accrual discussed above.

     We also accrue environmental remediation costs for our natural gas gathering and processing facilities, primarily related to soil and groundwater contamination. At September 30, 2005, we had accrued liabilities totaling approximately $8 million for these costs.

     Actual costs incurred for these matters will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by the EPA and other governmental authorities and other factors.

     In August 2004, the New Mexico Environment Department (NMED) issued a Notice of Violation (NOV) to one of our subsidiaries, Williams Field Services Company (WFS), alleging various air permit violations primarily related to WFS’s alleged failure to control volatile organic compound emissions from three conventional dehydrators in 2001. Additionally, in August 2004, we discovered and self-disclosed to the NMED that WFS was out of compliance with certain requirements of the operating permit issued under Title V of the Clean Air Act Amendments of 1990 at the Kutz gas processing plant. Both of these matters have been resolved.

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 September 30, 2005, we had accrued liabilities of approximately $11 million for such excess costs.

     We are also in discussions with defendants involved in two class action damages lawsuits involving this former chemical fertilizer business. Settlement among those defendants 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 has filed a Motion to Compel us to participate in arbitration regarding the contractual obligations. A hearing was held on that Motion on September 2, 2004, and the judge ordered the Motion to Compel and subsequent issues severed from the class action. Our efforts to remove the severed case to the United States District Court for the Northern District of Florida in Pensacola were unsuccessful. On September 8, 2005, we filed our Motion to Dismiss in state court. A status conference with the court is scheduled for November 22, 2005.

Other

     At September 30, 2005, we have accrued environmental liabilities totaling approximately $27 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; and
	•		former exploration and production and mining operations.

Notes (Continued)

     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 to the EPA a self-disclosure letter 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. On August 25, 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. Discussion between the EPA, the DOJ and Williams Refining to resolve the allegations of noncompliance are ongoing. In connection with the sale of the Memphis refinery in March 2003, we also have certain indemnification obligations to the purchaser.

     In January 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 WFS 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 are analyzing the proposed penalty and are in the process of negotiating a resolution with the current plant owner and the ODEQ.

     In November, 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 non-compliance and to assess a penalty accordingly. Gulf Liquids offered $91,500 as a single, final, 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 connection with agreements 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.

Notes (Continued)

     As a result of these settlements, Transco has been sued by certain producers seeking indemnification from Transco. Transco is currently a defendant in one lawsuit in which a producer has asserted damages, including interest calculated through September 30, 2005, of approximately $10 million. On July 11, 2003, at the conclusion of the trial, the judge ruled in Transco’s favor and subsequently entered a formal judgment. The plaintiff appealed and on October 14, 2005, the appeal was denied.

Will Price (formerly Quinque)

     On June 8, 2001, fourteen of our entities were named as defendants in a nationwide class action lawsuit that had been pending against other defendants, generally pipeline and gathering companies, since 2000. The plaintiffs allege 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. After the court denied class action certification and while motions to dismiss for lack of personal jurisdiction were pending, the court granted the plaintiffs’ motion to amend their petition on July 29, 2003. The fourth amended petition, which was filed on July 29, 2003, deletes all of our defendants except two Midstream subsidiaries. All defendants have opposed class certification, and a hearing on plaintiffs’ second motion to certify the class was held on April 1, 2005. We anticipate receiving a decision in late 2005.

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. On April 9, 1999, the DOJ announced that it was declining to intervene in any of the Grynberg qui tam cases, including the action filed in federal court in Colorado against us. On October 21, 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui tam 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. The defendants filed a number of joint motions to dismiss Grynberg’s claims on subject matter jurisdictional bases. 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 in the process of considering whether to affirm or reject the special master’s recommendations and has scheduled oral argument for 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 the defendants 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 defendants 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. Our motion to stay the proceedings in this case based on the pendency of the False Claims Act litigation discussed in the preceding paragraph was granted in January 2003. In September 2004, Grynberg successfully moved to lift the stay and 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 has been set for May 2006.

Notes (Continued)

Securities class actions

     Numerous shareholder class action suits have been filed against us 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 filed 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. The amended complaint of the WilTel securities holders was filed in September 2002, and the amended complaint of our securities holders was filed in October 2002. This amendment added numerous claims related to Power. Defendants moved to dismiss the complaints and the Court largely denied the motions. The parties are currently engaged in discovery. On April 2, 2004, the lead plaintiff for the purported class of our securities holders filed a partial motion for summary judgment with respect to certain disclosures made in connection with our public offerings during the class period. That lead plaintiff subsequently filed to withdraw from the proceeding and a process was held to determine the lead plaintiff. This process has concluded with the appointment of a new lead plaintiff and lead counsel and the motion for summary judgment is no longer being pursued. The appointment of a new lead plaintiff also resulted in a revised schedule with a trial date currently set for August 16, 2006. 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. We have directors and officers insurance which we believe provides coverage for these claims, but there can be no assurance that the ultimate resolution of this litigation will not include some amount outside of insurance coverage.

     In addition, four class action complaints were filed against us, the members of our Board of Directors and members of our benefits and investment committees under the Employee Retirement Income Security Act (ERISA) by participants in our 401(k) plan. In September 2005, the parties agreed to settle these consolidated matters for $55 million. Of this amount, we will pay $5 million, which has been accrued, and our insurance carriers will pay $50 million. This settlement received preliminary court approval on September 28, 2005. A fairness hearing is scheduled for November 16, 2005. The U.S. Department of Labor was also independently investigating our employee benefit plans but communicated its decision on November 1, 2005, to close its investigation of the 401(k) plan’s stock investments.

Oklahoma securities investigation

     On April 26, 2002, the Oklahoma Department of Securities issued an order initiating an investigation of us and WilTel regarding issues associated with the spin-off of WilTel and regarding the WilTel bankruptcy. We have no pending inquiries in this investigation, but are committed to cooperate fully in the investigation.

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

Notes (Continued)

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.

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. The FERC and RCA presiding administrative law judges rendered their joint and individual initial decisions during the third quarter of 2004. 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. Based on our computation and assessment of ultimate ruling terms that would be considered probable, we recorded an accrual of approximately $134 million in the third quarter of 2004. Additional interest on the Quality Bank accrual is being accrued each quarter. Because the application of certain aspects of the initial decisions are subject to interpretation, we have calculated the reasonably possible impact of the decisions, if fully adopted by the FERC and RCA, to result in additional exposure to us of approximately $32 million more than we have accrued at September 30, 2005.

     On October 20, 2005, the FERC and the RCA issued substantially similar orders regarding the initial decisions. Consistent with the 2005 Highway Reauthorization Bill enacted on August 10, 2005, the two orders eliminate our retroactive exposure for refunds prior to February 1, 2000. The orders also generally affirm the initial decisions except for some modifications to the residual product cuts valuation methodology. We are evaluating the impact of the orders on our retroactive liability as well as the residual product cuts valuation changes. Although the exact impact of the orders is not known at this time, and based on the orders as written we believe the overall impact of the change in retroactive periods precludes our previously disclosed concerns for reasonably possible exposure for amounts in addition to those currently accrued. Requests for rehearing are due within 30 days of the issuance of the FERC order and within 15 days of the issuance of the RCA order. We expect the filing of rehearing requests at the FERC and subsequent appeals to the Circuit Court.

Deepwater construction litigation

     In a lawsuit pending in federal court in Houston, Texas, Technip Offshore, Inc., is seeking approximately $8.6 million from two of our subsidiaries. The suit alleges that we breached a contract for the construction of deepwater export pipelines connected to the Devils Tower Spar in the Gulf of Mexico. We have filed counterclaims seeking $4.2 million in liquidated delay damages. Each party has posted a letter of credit covering the value of the claims pending against it.

Colorado royalty litigation

     On June 27, 2002, a royalty owner in the Piceance basin of Colorado filed suit against one of our Exploration & Production subsidiaries alleging that we breached our lease agreements and violated the Colorado Deceptive Trade Practices Act (CDTA) by making various deductions from his royalty payments from 1996 to date. On August 2, 2004, the jury returned its verdict in the amount of $4.1 million for the plaintiff. The verdict included a finding under the CDTA which could have potentially tripled the damage award. On November 30, 2004, the court issued an order setting aside the plaintiff’s CDTA claims, but left intact the $4.1 million award. We are appealing the judgment to the Colorado Court of Appeals.

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. On the same date, Power was served with a subpoena from the

Notes (Continued)

city related to the tax assessment. During July 2005, the city held hearings on this matter. 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 which will be heard at the city level. 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.

San Juan basin gas entitlements

     One of our Exploration & Production subsidiaries is involved in a dispute with another joint interest owner in multiple federal oil and gas units located in the San Juan basin. The dispute involves various accounting issues relating to payout determinations in these federal units and associated claims for retroactive adjustment of entitlements to gas production. We have settled these disputes for a payment of approximately $23.5 million.

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 filed a Plea in Intervention and Third Party Petition adding 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 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. Various motions for summary judgment are pending before the court. Depending in part on the resolution of these various motions, it is reasonably possible that the contractors and sureties might be awarded damages against us in these various cases for an amount up to $25 million. Trial in the Harris County cases is set for March 27, 2006.

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 September 30, 2005, 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.

Notes (Continued)

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 September 30, 2005, Power’s estimated committed payments under these contracts range from approximately $402 million to $420 million annually through 2014 and decline over the remaining eight years to $57 million in 2022. Total committed payments under these contracts over the next eighteen years are approximately $5.9 billion.

Guarantees

     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.

     A foreign bank is a defendant in litigation related to a loan they provided to us. We have repaid the loan and indemnified the bank for legal fees and potential losses that may result from this litigation. We are unable to determine the maximum amount of future payments that we could be required to pay as it is dependent upon the ultimate resolution of the claim. However, we believe the probability is remote that a judgment will be entered against the bank that we will have to pay. The carrying value of this guarantee is $0.1 million at September 30, 2005.

     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, 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 2006 and have no carrying value.

     We have provided guarantees in the event of nonpayment by WilTel on certain lease performance obligations that extend through 2042 and have a maximum exposure of approximately $48 million at September 30, 2005. Our exposure declines systematically throughout the remaining term of WilTel’s obligations. The carrying value of these guarantees is approximately $43 million at September 30, 2005.

     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 September 30, 2005.

     Former managing directors of Gulf Liquids are involved in litigation related to the construction of the gas processing plants. Gulf Liquids has indemnity obligations to the former directors for legal fees and potential losses that may result from this litigation. We are unable to determine the maximum amount of future payments that we could be required to pay as it is dependent upon the ultimate resolution of the litigation. However, we believe the probability is remote that a judgment will be entered against the former directors that we will have to pay. These legal fees and any judgment should be recoverable under a directors and officers insurance policy; thus, no amounts have been accrued for this contingent obligation.

     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

Notes (Continued)

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.

13. Comprehensive income (loss)

     Comprehensive income (loss) is as follows:

		Three months ended								Nine months ended
		September 30,								September 30,
		2005				2004				2005				2004
		(Millions)								(Millions)
Net income		$	4.4			$	98.6			$	246.8			$	90.3
Other comprehensive income (loss):
Net realized losses on securities			—				—				—				3.0
Unrealized losses on derivative instruments			(390.3	)			(227.9	)			(663.2	)			(496.3	)
Net reclassification into earnings of derivative instrument losses			65.2				52.4				187.7				150.4
Foreign currency translation adjustments			14.7				18.3				9.6				6.8
Minimum pension liability adjustment			.8				(.3	)			.8				.4
Other comprehensive loss before taxes			(309.6	)			(157.5	)			(465.1	)			(335.7	)
Income tax benefit on other comprehensive loss			124.4				66.7				181.9				130.4
Other comprehensive loss			(185.2	)			(90.8	)			(283.2	)			(205.3	)
Comprehensive income (loss)		$	(180.8	)		$	7.8			$	(36.4	)		$	(115.0	)

     Unrealized 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 losses at September 30, 2005, includes net unrealized losses on forward power purchases and sales of approximately $523 million and net unrealized losses on forward natural gas purchases and sales of approximately $140 million. The increases in these losses in third-quarter 2005 are due to increases in the prices of these commodities.

14. Segment disclosures

Segments and reclassification of operations

     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 and certain continuing operations that were included within the previously reported International and Petroleum Services segments.

Segments — performance measurement

     We currently evaluate performance based upon segment profit (loss) from operations, which includes revenues from external and internal customers, operating costs and expenses, depreciation, depletion and amortization, equity earnings (losses) and income (loss) from investments including gains/losses on 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.

     During 2004, Power was party to intercompany interest rate swaps with the corporate parent, the effect of which is included in Power’s segment revenues and segment profit (loss) as shown in the reconciliation within the following tables. The results of interest rate swaps with external counterparties are shown as Interest rate swap loss in the Consolidated Statement of Operations below operating income. These swaps were terminated in the fourth quarter of 2004.

     The majority of energy commodity hedging by certain of our business units is done through intercompany derivatives with Power 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 intercompany sales.

Notes (Continued)

14. Segment disclosures (Continued)

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

										Exploration				Midstream
						Gas				&				Gas &
		Power				Pipeline				Production				Liquids				Other				Eliminations				Total
		(Millions)
Three months ended September 30, 2005
Segment revenues:
External		$	2,043.4			$	344.3			$	(52.0	)		$	744.5			$	2.1			$	—			$	3,082.3
Internal			199.5				1.5				370.4				10.2				4.2				(585.8	)			—
Total segment revenues		$	2,242.9			$	345.8			$	318.4			$	754.7			$	6.3			$	(585.8	)		$	3,082.3
Segment profit (loss)		$	(226.4	)		$	161.1			$	158.8			$	121.1			$	(10.1	)		$	—			$	204.5
Less:
Equity earnings (losses)			1.0				17.0				5.8				3.2				(9.4	)			—				17.6
Segment operating income (loss)		$	(227.4	)		$	144.1			$	153.0			$	117.9			$	(0.7	)		$	—				186.9
General corporate expenses																											(42.8	)
Consolidated operating income																										$	144.1
Three months ended September 30, 2004
Segment revenues:
External		$	2,338.8			$	318.1			$	(22.2	)		$	738.2			$	2.3			$	—			$	3,375.2
Internal			249.9				2.9				231.5				11.8				4.4				(500.5	)			—
Total segment revenues			2,588.7				321.0				209.3				750.0				6.7				(500.5	)			3,375.2
Less intercompany interest rate swap loss			(15.5	)			—				—				—				—				15.5				—
Total revenues		$	2,604.2			$	321.0			$	209.3			$	750.0			$	6.7			$	(516.0	)		$	3,375.2
Segment profit		$	109.3			$	148.8			$	70.1			$	105.4			$	2.4			$	—			$	436.0
Less:
Equity earnings (losses)			.6				11.4				2.6				1.4				(.1	)			—				15.9
Intercompany interest rate swap loss			(15.5	)			—				—				—				—				—				(15.5	)
Segment operating income		$	124.2			$	137.4			$	67.5			$	104.0			$	2.5			$	—				435.6
General corporate expenses																											(24.1	)
Consolidated operating income																										$	411.5
										Exploration				Midstream
						Gas				&				Gas &
		Power				Pipeline				Production				Liquids				Other				Eliminations				Total
		(Millions)
Nine months ended September 30, 2005
Segment revenues:
External		$	5,682.4			$	1,029.4			$	(120.3	)		$	2,309.5			$	6.5			$	—			$	8,907.5
Internal			624.8				8.7				969.2				32.3				12.9				(1,647.9	)			—
Total segment revenues		$	6,307.2			$	1,038.1			$	848.9			$	2,341.8			$	19.4			$	(1,647.9	)		$	8,907.5
Segment profit (loss)		$	(187.3	)		$	493.0			$	380.8			$	358.8			$	(74.7	)		$	—			$	970.6
Less:
Equity earnings (losses)			3.0				36.3				12.9				14.4				(21.5	)			—				45.1
Income (loss) from investments			—				—				—				.7				(49.1	)			—				(48.4	)
Segment operating income		$	(190.3	)		$	456.7			$	367.9			$	343.7			$	(4.1	)		$	—				973.9
General corporate expenses																											(106.3	)
Consolidated operating income																										$	867.6
Nine months ended September 30, 2004
Segment revenues:
External		$	6,561.4			$	999.3			$	(56.3	)		$	1,985.5			$	7.2			$	—			$	9,497.1
Internal			655.8				11.7				619.8				30.0				19.1				(1,336.4	)			—
Total segment revenues			7,217.2				1,011.0				563.5				2,015.5				26.3				(1,336.4	)			9,497.1
Less intercompany interest rate swap loss			(16.6	)			—				—				—				—				16.6				—
Total revenues		$	7,233.8			$	1,011.0			$	563.5			$	2,015.5			$	26.3			$	(1,353.0	)		$	9,497.1
Segment profit (loss)		$	121.1			$	429.0			$	164.9			$	314.0			$	(20.6	)		$	—			$	1,008.4
Less:
Equity earnings (losses)			.4				20.4				8.7				9.1				(.4	)			—				38.2
Loss from investments			—				(1.0	)			—				(.3	)			(17.3	)			—				(18.6	)
Intercompany interest rate swap loss			(16.6	)			—				—				—				—				—				(16.6	)
Segment operating income (loss)		$	137.3			$	409.6			$	156.2			$	305.2			$	(2.9	)		$	—				1,005.4
General corporate expenses																											(84.5	)
Consolidated operating income																										$	920.9