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, 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 October 31, 2006
Common Stock, $1 par value		596,338,450 Shares

 

 

The Williams Companies, Inc.

Index

		Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Income — Three and Nine Months Ended September 30, 2006 and 2005			3
Consolidated Balance Sheet — September 30, 2006 and December 31, 2005			4
Consolidated Statement of Cash Flows — Nine Months Ended September 30, 2006 and 2005			5
Notes to Consolidated Financial Statements			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
Item 3. Quantitative and Qualitative Disclosures about Market Risk			56
Item 4. Controls and Procedures			58
Part II. Other Information			59
Item 1. Legal Proceedings			59
Item 1A. Risk Factors			59
Item 6. Exhibits			59
Computation of Ratio of Earnings to Fixed Charges
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of Pursuant to Section 906

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

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

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

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

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

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

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

      Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item IA. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2005.

The Williams Companies, Inc.

		Three months								Nine months
		ended September 30,								ended September 30,
(Dollars in millions, except per-share amounts)		2006				2005				2006				2005
Revenues:
Exploration & Production		$	371.1			$	318.4			$	1,069.4			$	848.9
Gas Pipeline			334.2				345.8				1,005.5				1,038.1
Midstream Gas & Liquids			1,117.0				754.7				3,139.9				2,341.8
Power			2,104.1				2,242.9				5,764.3				6,307.2
Other			6.4				6.3				19.8				19.4
Intercompany eliminations			(632.8	)			(585.8	)			(1,956.3	)			(1,647.9	)
Total revenues			3,300.0				3,082.3				9,042.6				8,907.5
Segment costs and expenses:
Costs and operating expenses			2,822.4				2,826.2				7,684.9				7,708.1
Selling, general and administrative expenses			128.0				90.6				308.3				226.8
Other (income) expense — net			(15.8	)			(21.4	)			23.6				(1.3	)
Total segment costs and expenses			2,934.6				2,895.4				8,016.8				7,933.6
General corporate expenses			35.0				42.8				99.3				106.3
Securities litigation settlement and related costs			3.4				—				165.3				—
Operating income (loss):
Exploration & Production			138.9				153.0				395.4				367.9
Gas Pipeline			99.3				144.1				339.0				456.7
Midstream Gas & Liquids			204.9				117.9				471.0				343.7
Power			(77.3	)			(227.4	)			(179.5	)			(190.3	)
Other			(.4	)			(0.7	)			(.1	)			(4.1	)
General corporate expenses			(35.0	)			(42.8	)			(99.3	)			(106.3	)
Securities litigation settlement and related costs			(3.4	)			—				(165.3	)			—
Total operating income			327.0				144.1				761.2				867.6
Interest accrued			(162.7	)			(166.0	)			(507.0	)			(495.3	)
Interest capitalized			4.8				1.8				11.8				4.3
Investing income			50.7				31.1				140.9				44.9
Early debt retirement costs			—				—				(31.4	)			—
Minority interest in income of consolidated subsidiaries			(12.1	)			(6.8	)			(27.5	)			(16.8	)
Other income (expense) — net			2.8				(1.1	)			18.9				12.5
Income from continuing operations before income taxes			210.5				3.1				366.9				417.2
Provision (benefit) for income taxes			100.4				(2.6	)			189.6				168.6
Income from continuing operations			110.1				5.7				177.3				248.6
Loss from discontinued operations			(3.9	)			(1.3	)			(15.2	)			(1.8	)
Net income		$	106.2			$	4.4			$	162.1			$	246.8
Basic earnings per common share:
Income from continuing operations		$	.19			$	.01			$	.30			$	.43
Loss from discontinued operations			(.01	)			—				(.03	)			—
Net income		$	.18			$	.01			$	.27			$	.43
Weighted-average shares (thousands)			596,199				572,543				594,406				569,426
Diluted earnings per common share:
Income from continuing operations		$	.19			$	.01			$	.29			$	.42
Loss from discontinued operations			(.01	)			—				(.02	)			—
Net income		$	.18			$	.01			$	.27			$	.42
Weighted-average shares (thousands)			609,062				580,735				608,045				604,749
Cash dividends per common share		$	.09			$	.075			$	.255			$	.175

See accompanying notes.

The Williams Companies, Inc.

		September 30,				December 31,
(Dollars in millions, except per-share amounts)		2006				2005
ASSETS
Current assets:
Cash and cash equivalents		$	1,074.6			$	1,597.2
Restricted cash			79.3				92.9
Accounts and notes receivable (net of allowance of $23.9 in 2006 and $86.6 in 2005)			1,232.9				1,613.8
Inventories			260.2				272.6
Derivative assets			2,311.3				5,299.7
Margin deposits			127.0				349.2
Assets of discontinued operations			5.3				12.8
Deferred income taxes			293.1				241.0
Other current assets and deferred charges			306.3				218.1
Total current assets			5,690.0				9,697.3
Restricted cash			40.9				36.5
Investments			929.5				887.8
Property, plant and equipment — net			13,651.8				12,409.2
Derivative assets			2,739.1				4,656.9
Goodwill			1,011.4				1,014.5
Other assets and deferred charges			758.8				740.4
Total assets		$	24,821.5			$	29,442.6
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	1,055.0			$	1,360.6
Accrued liabilities			1,229.5				1,121.9
Customer margin deposits payable			77.4				320.7
Liabilities of discontinued operations			1.3				1.2
Derivative liabilities			2,246.0				5,523.2
Long-term debt due within one year			142.3				122.6
Total current liabilities			4,751.5				8,450.2
Long-term debt			7,275.2				7,590.5
Deferred income taxes			2,897.7				2,508.9
Derivative liabilities			2,377.4				4,331.1
Other liabilities and deferred income			1,010.1				920.3
Contingent liabilities and commitments (Note 11)
Minority interests in consolidated subsidiaries			438.4				214.1
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 601.8 million shares issued at September 30, 2006 and 579.1 million shares issued at December 31, 2005)			601.8				579.1
Capital in excess of par value			6,567.6				6,327.8
Accumulated deficit			(1,125.6	)			(1,135.9	)
Accumulated other comprehensive income (loss)			68.7				(297.8	)
Other			(.1	)			(4.5	)
			6,112.4				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			6,071.2				5,427.5
Total liabilities and stockholders’ equity		$	24,821.5			$	29,442.6

See accompanying notes.

The Williams Companies, Inc.

		Nine months ended September 30,
(Dollars in millions)		2006				2005
OPERATING ACTIVITIES:
Net income		$	162.1			$	246.8
Adjustments to reconcile to net cash provided by operations:
Loss from discontinued operations			15.2				1.8
Depreciation, depletion and amortization			627.9				545.9
Accrual for securities litigation settlement and related costs			165.3				—
Provision (benefit) for deferred income taxes			129.0				(63.1	)
Provision for loss on investments, property and other assets			6.2				56.3
Net gain on disposition of assets			(13.6	)			(47.0	)
Early debt retirement costs			31.4				—
Minority interest in income of consolidated subsidiaries			27.5				16.8
Amortization of stock-based awards			32.5				9.9
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable			359.1				(115.0	)
Inventories			12.5				(39.9	)
Margin deposits and customer margin deposits payable			(21.1	)			61.0
Other current assets and deferred charges			(47.1	)			(2.2	)
Accounts payable			(297.9	)			114.5
Accrued liabilities			(185.9	)			52.7
Changes in current and noncurrent derivative assets and liabilities			252.1				203.1
Other, including changes in noncurrent assets and liabilities			52.5				40.7
Net cash provided by operating activities of continuing operations			1,307.7				1,082.3
Net cash provided by operating activities of discontinued operations			6.6				—
Net cash provided by operating activities			1,314.3				1,082.3
FINANCING ACTIVITIES:
Proceeds from long-term debt			699.4				—
Payments of long-term debt			(773.6	)			(243.6	)
Proceeds from issuance of common stock			21.6				303.4
Proceeds from sale of limited partner units of consolidated partnership			225.2				111.0
Payments for debt issuance costs and amendment fees			(26.9	)			(29.6	)
Premiums paid on early debt retirement			(25.8	)			—
Dividends paid			(151.8	)			(100.0	)
Dividends and distributions paid to minority interests			(28.1	)			(19.8	)
Changes in restricted cash			5.0				37.1
Changes in cash overdrafts			(17.0	)			58.7
Other — net			(1.3	)			.1
Net cash provided (used) by financing activities			(73.3	)			117.3
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures			(1,758.9	)			(885.9	)
Net proceeds from dispositions			(10.6	)			39.0
Proceeds from contract termination payment			3.3				87.9
Changes in accounts payable and accrued liabilities			37.8				(4.0	)
Purchases of investments/advances to affiliates			(45.6	)			(98.2	)
Purchases of auction rate securities			(375.8	)			(171.3	)
Proceeds from sales of auction rate securities			319.8				115.2
Proceeds from sales of businesses			—				31.4
Proceeds received on sale of note from WilTel			—				54.7
Proceeds from dispositions of investments and other assets			51.3				51.6
Other — net			15.1				10.5
Net cash used by investing activities			(1,763.6	)			(769.1	)
Increase (decrease) in cash and cash equivalents			(522.6	)			430.5
Cash and cash equivalents at beginning of period			1,597.2				930.0
Cash and cash equivalents at end of period		$	1,074.6			$	1,360.5

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 September 30, 2006, and results of operations for the three and nine months ended September 30, 2006 and 2005 and cash flows for the nine months ended September 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 or otherwise disposed of 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 Income are included in the following table:

		Three months ended								Nine months ended
		September 30,								September 30,
		2006				2005				2006				2005
		(Millions)								(Millions)
Costs and operating expenses:
Gas Pipeline
Liability reversal associated with a favorable rate case ruling involving adjustments to estimated gas purchase costs for operations in prior periods		$	—			$	(14.2	)		$	—			$	(14.2	)
Adjustments to correct the carrying value of certain liabilities recorded in prior periods			—				—				—				(12.1	)
Midstream
Adjustment of accounts payable accrual (excluding $.8 million recorded in SG&A)			9.8				—				9.8				—
Selling, general and administrative expenses (SG&A):
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	)
Other (income) expense — net (within segment costs and expenses):
Exploration & Production
Gains on sales of certain natural gas properties			—				(21.7	)			—				(29.6	)
Midstream
Gains on sales of properties			(7.9	)			—				(7.9	)			—
Losses on asset retirements, primarily due to the impact of accelerating the timing of abandonment			5.2				—				5.2				—
Accrual for Gulf Liquids litigation contingency. Associated with this contingency is an interest expense accrual of $0.6 million for the third quarter and $20.6 million year-to-date, which is included in interest accrued (see Note 11)			2.4				—				70.4				—
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			3.5				0.4				3.5				13.5
Reduction of contingent obligations associated with our former distributive power generation business			(12.7	)			—				(12.7	)			—
General corporate expenses
Other
Insurance settlement charges associated with certain insurance coverage allocation issues			—				13.8				—				13.8
Investing income (loss):
Midstream
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	)
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	)			—
$6 million claim settlement related to a former exploration business, net of taxes of $2.3 million			(3.7	)			—				(3.7	)			—

Notes (Continued)

Note 4. Provision (Benefit) for Income Taxes

     The provision (benefit) for income taxes includes:

		Three months ended								Nine months ended
		September 30,								September 30,
		2006				2005				2006				2005
		(Millions)								(Millions)
Current:
Federal		$	5.2			$	205.6			$	17.9			$	212.9
State			(.8	)			(1.3	)			10.9				6.7
Foreign			14.6				5.8				31.8				12.1
			19.0				210.1				60.6				231.7
Deferred:
Federal			52.3				(212.6	)			85.0				(73.5	)
State			21.5				(1.3	)			25.7				14.8
Foreign			7.6				1.2				18.3				(4.4	)
			81.4				(212.7	)			129.0				(63.1	)
Total provision (benefit)		$	100.4			$	(2.6	)		$	189.6			$	168.6

     The effective income tax rate for the three months ended September 30, 2006, is greater than the federal statutory rate due primarily to the effect of state income taxes and taxes on foreign operations.

     The effective income tax rate for the nine months ended September 30, 2006, is greater than the federal statutory rate due primarily to the effect of state income taxes, taxes on 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 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 taxes on 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 taxes on foreign operations.

Notes (Continued)

Note 5. Earnings Per Common Share from Continuing Operations

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

		Three months ended								Nine months ended
		September 30,								September 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 from continuing operations available to common stockholders for basic and diluted earnings per share (1)		$	110.1			$	5.7			$	177.3			$	248.6
Basic weighted-average shares (2)			596,199				572,543				594,406				569,426
Effect of dilutive securities:
Unvested deferred shares (3)			1,032				2,999				921				2,849
Stock options			4,503				5,193				4,351				4,926
Convertible debentures			7,328				—				8,367				27,548
Diluted weighted-average shares			609,062				580,735				608,045				604,749
Earnings per share from continuing operations:
Basic		$	.19			$	.01			$	.30			$	.43
Diluted		$	.19			$	.01			$	.29			$	.42

     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 for the three months ended September 30, 2005. 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 $53.7 million for the three months ended September 30, 2005.

     The table below includes information related to stock 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.

		September 30,				September 30,
		2006				2005
Options excluded (millions)			4.2				4.8
Weighted-average exercise prices of options excluded		$	35.33			$	35.23
Exercise price ranges of options excluded		$	23.88-$42.29			$	23.88-$42.29
Third quarter weighted-average market price		$	23.87			$	21.75

Notes (Continued)

Note 6. Employee Benefit Plans

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

		Pension Benefits
		Three months								Nine months
		ended September 30,								ended September 30,
		2006				2005				2006				2005
		(Millions)								(Millions)
Components of net periodic pension expense (income):
Service cost		$	5.5			$	5.4			$	16.6			$	16.2
Interest cost			12.7				12.0				37.6				35.8
Expected return on plan assets			(16.7	)			(17.8	)			(50.1	)			(53.3	)
Amortization of prior service credit			(.1	)			(.1	)			(.4	)			(.3	)
Recognized net actuarial (gain) loss			5.2				1.7				14.7				(8.3	)
Regulatory asset amortization (deferral)			—				.7				(.1	)			.3
Settlement/curtailment expense			—				.1				—				2.7
Net periodic pension expense (income)		$	6.6			$	2.0			$	18.3			$	(6.9	)

		Other Postretirement Benefits
		Three months								Nine months
		ended September 30,								ended September 30,
		2006				2005				2006				2005
		(Millions)								(Millions)
Components of net periodic other postretirement benefit expense:
Service cost		$	.8			$	.8			$	2.4			$	2.3
Interest cost			4.4				5.8				13.0				14.6
Expected return on plan assets			(2.7	)			(2.9	)			(8.3	)			(8.6	)
Amortization of prior service credit			(.1	)			(.1	)			(.3	)			(4.2	)
Recognized net actuarial loss			—				.9				—				2.4
Regulatory asset amortization			1.8				1.5				5.4				5.3
Net periodic other postretirement benefit expense		$	4.2			$	6.0			$	12.2			$	11.8

     Net periodic pension expense (income) 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 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 September 30, 2006, we have contributed $3.2 million to our pension plans and $11.0 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 $4 million to our other postretirement benefit plans in 2006 for a total of approximately $15 million.

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 September 30, 2006, 42.8 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 19.9 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.

Notes (Continued)

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 Financial Accounting Standards Board (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 Income for the nine months ending September 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 FASB Statement No. 123(R), “Share-Based Payment” (SFAS No. 123(R)), using the modified-prospective method. Under this method, compensation cost recognized in the first nine 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 most 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). The performance targets for certain performance based deferred shares have not been established and therefore expense is not currently recognized. Results for prior periods have not been restated.

     Total stock-based compensation expense for the three and nine months ending September 30, 2006, was $11.1 million and $32.5 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 September 30, 2006, was approximately $61 million, which does not include the effect of estimated forfeitures of $2.2 million. This amount is comprised of approximately $17 million related to stock options and approximately $44 million related to deferred shares. These amounts are expected to be recognized over a weighted-average period of 1.8 years.

     As a result of adopting SFAS No. 123(R), our income from continuing operations before income taxes and net income for the three months ending September 30, 2006, are approximately $3.9 million and $2.3 million lower, respectively, and for the nine months ending September 30, 2006, are approximately $14.5 million and $8.9 million lower, respectively, than if we continued to account for share-based compensation under APB No. 25. For the nine months ending September 30, 2006, basic and diluted earnings per share are $.02 and $.01 lower, respectively, 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 nine months ending September 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.

		Three months ended				Nine months ended
		September 30, 2005				September 30, 2005
		(Dollars in millions, except				(Dollars in millions, except
		per share amounts)				per share amounts)
Net income, as reported		$	4.4			$	246.8
Add: Stock-based employee compensation expense included in the Consolidated Statement of Income, net of related tax effects			2.8				6.8
Deduct: Stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects			(4.8	)			(12.8	)
Pro forma net income		$	2.4			$	240.8
Earnings per share:
Basic-as reported		$	.01			$	.43
Basic-pro forma		$	—			$	.42
Diluted-as reported		$	.01			$	.42
Diluted-pro forma		$	—			$	.41

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.

Notes (Continued)

     The following summary reflects stock option activity and related information for the nine-month period ending September 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			$	21.64
Exercised			(1.9	)		$	11.40			$	22.7
Cancelled			(.7	)		$	30.11
Outstanding at September 30, 2006			19.0			$	17.01			$	178.7
Exercisable at September 30, 2006			14.5			$	16.97			$	148.1

     The following summary provides additional information about stock options that are outstanding and exercisable at September 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			9.0			$	7.08				6.0				7.7			$	6.59				5.8
$10.38 to $16.40			1.0			$	15.50				4.0				1.0			$	15.55				4.0
$17.10 to $31.58			5.7			$	21.29				6.9				2.5			$	22.79				4.6
$33.51 to $42.28			3.3			$	37.62				1.8				3.3			$	37.62				1.8
Total			19.0			$	17.01				5.5				14.5			$	16.97				4.6

     The estimated weighted-average grant-date fair value of stock options granted during the first nine months of 2006 is $8.35 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 nine months of 2006 were estimated using the following assumptions:

Expected dividend yield			1.42	%
Expected volatility			36.30	%
Risk-free interest rate			4.66	%
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 $21.6 million during the first nine 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.

Notes (Continued)

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

						Weighted-
						Average
Deferred Shares		Shares				Fair Value*
		(Millions)
Nonvested at December 31, 2005			2.8			$	14.60
Granted			1.4			$	21.85
Forfeited			(.1	)		$	17.96
Vested			(.6	)		$	11.59
Nonvested at September 30, 2006			3.5			$	18.40

     The total market value of shares vested and issued during the first nine months of 2006 was approximately $11.5 million.

     Performance-based share awards issued under the Plan represent 35 percent of nonvested deferred shares outstanding at September 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 September 30, 2006 and December 31, 2005 are:

		September 30,				December 31,
		2006				2005
		(Millions)
Natural gas in underground storage		$	93.1			$	90.4
Materials, supplies and other			86.7				82.2
Natural gas liquids			80.4				100.0
		$	260.2			$	272.6

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 Partners 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 generally 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;

Notes (Continued)

•

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

		Letters of Credit at
		September 30, 2006
		(Millions)
$500 million unsecured credit facilities		$	436.5
$700 million unsecured credit facilities		$	505.6
$1.5 billion unsecured credit facility		$	45.6

   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 October 2006, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

     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. In October 2006, Northwest Pipeline completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

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 September 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

Notes (Continued)

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 $29 million at September 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.

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

	•		Class action litigation in federal court in Nevada alleging that we manipulated gas prices for direct purchasers of gas in California. We have 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. The court granted preliminary approval of our settlement of this matter for $15.6 million, and we paid this amount into escrow on September 5, 2006 pending final 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.

Earlier this year, we settled a case for $9.15 million in Federal court in New York based on an allegation of manipulation of the NYMEX gas market. It is reasonably possible that additional amounts may be necessary to resolve the remaining outstanding litigation in this area, the amount of which cannot be reasonably estimated at this time.

Notes (Continued)

Mobile Bay Expansion

     In December 2002, an administrative law judge at the FERC issued an initial decision in Transco’s 2001 general rate case which, among other things, rejected the recovery of the costs of Transco’s Mobile Bay expansion project from its shippers on a “rolled-in” basis and found that incremental 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 $91 million, excluding interest, through September 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 September 30, 2006, we had accrued liabilities of $12 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 September 30, 2006, we have accrued liabilities totaling approximately $5 million for these costs. We expect that these costs will be recoverable through Northwest Pipeline’s rates.

     We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At September 30, 2006, we have accrued liabilities totaling approximately $6 million for these costs.

Notes (Continued)

     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 our Roan Cliffs and Hayburn Gas Plants in Garfield County, Colorado. On September 13, 2006, we met with the CDPHE to discuss the allegations contained in the NOV, and we will provide additional requested information to the agency.

     In August 2006, the CDPHE issued a NOV to Williams Production RMT Company related to our Grand Valley Oil Separation and Evaporation Facility located in Garfield County, Colorado in which the CDPHE alleged that we failed to obtain a construction permit and to comply with certain provisions of our existing permit. On September 19, 2006, we met with the CDPHE and will provide additional requested information to the agency.

     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.

  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, 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.

Notes (Continued)

  Other

     At September 30, 2006, we have accrued environmental liabilities totaling approximately $25 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 in the second quarter of 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, and the current owner 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 2006, we settled all issues with the ODEQ, and have paid approximately $400,000 to settle the penalty. This matter is now resolved.

     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, 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, but the amount cannot be reasonably estimated at this time.

Notes (Continued)

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 in 2002 and Texas Gas Transmission Corporation in 2003, we agreed to indemnify the purchasers for any liability relating to this claim, including legal fees. The maximum amount of future payments that we could potentially be required to pay under these indemnifications depends upon the ultimate resolution of the claim and cannot currently be determined. Grynberg had also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. In 1999, the DOJ announced that it was declining to intervene in any of the Grynberg cases. Also in 1999, the Panel on Multi-District Litigation transferred all of these cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. Grynberg’s measurement claims remained pending against us and the other defendants; the court previously dismissed Grynberg’s royalty valuation claims. In May 2005, the court-appointed special master entered a report which recommended that the claims against our Gas Pipeline and Midstream subsidiaries be dismissed but upheld the claims against our Exploration & Production subsidiaries against our jurisdictional challenge. On October 20, 2006, the District Court dismissed all claims against us and our wholly owned subsidiaries.

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

Notes (Continued)

  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. On October 4, 2006, the court granted preliminary approval of the settlement, and the settlement amount will be paid into escrow pending final approval. Of the total settlement amount, we expect to pay approximately $145 million in cash to fund the settlement, and expect the balance to be funded by our insurers. The exact amount of our payment is subject to final determination and timing of certain insurer coverage allocations. The court has set a hearing on the fairness of the settlement on February 9, 2007. 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 September 30, 2006, we have recorded pre-tax charges of approximately $165 million for this settlement and related legal 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. The extent of the obligation is presently unknown and cannot be estimated, but it is reasonably possible that our exposure materially exceeds amounts accrued for this matter.

     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. On October 24, 2006, the court held its hearing on the fairness of the settlement and issued its final 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.

  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

Notes (Continued)

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.

     The Quality Bank Administrator issued his interpretations of the payment obligations under the FERC Final Order, and we and others filed exceptions to these instructions with the FERC. We expect the FERC’s ruling on these payment instruction exceptions later in the fourth quarter of 2006. Once the FERC rules, the Administrator will invoice us for amounts due, and we will be required to pay the invoiced amounts, subject to the outcome of the appeals of the FERC Final Order. We estimate that our net obligation could be as much as $115 million. Amounts accrued in excess of this estimated obligation will be retained pending resolution of all 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. 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 we and AES Redondo Beach have filed notices of appeal that will be heard at the city level. On October 20, 2006, the city hearing officer for the appeal of the pre-2005 amounts issued a draft decision affirming our utility users tax liability and reversing AES Redondo’s liability because the officer ruled that AES Redondo is an exempt public utility. Before a final decision, we have an opportunity to present oral arguments on the draft decision at a hearing that has not been scheduled. Upon final determination, we may be required to pay the full amount of any final determination prior to further appeal to the California state courts.

     Since the first assessment in 2005, we have received subsequent assessments (for the periods October 2004 through June 2006) totaling approximately $4 million (inclusive of interest and penalties). We have protested all these assessments and requested hearings on them. We and AES Redondo have also filed separate refund actions in Los Angeles Superior Court related to certain taxes paid since the initial 2005 notice of assessment. We believe that under our tolling agreement related to the Redondo Beach generating facility, AES Redondo Beach is responsible for taxes of the nature asserted by the city; however, AES Redondo Beach has notified us that it does not agree.

  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

Notes (Continued)

Louisiana and Texas. In January 2002, NAICO added Gulf Liquids’ co-venturer Power to the suits as a third-party defendant. Gulf Liquids asserted claims against the contractors and sureties for, among other things, breach of contract requesting contractual and consequential damages from $40 million to $80 million, any of which is subject to a sharing arrangement with XL Insurance Company.

     At the conclusion of the consolidated trial of the asserted contract and tort claims, 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 the first quarter of 2007. Based on our interpretation of the jury verdicts, we have estimated exposure for actual damages of approximately $68 million plus potential interest of approximately $20.6 million, all of which have been accrued as of September 30, 2006. In addition, it is reasonably possible that any ultimate judgment may include additional amounts of approximately $185 million in excess of our accrual, which primarily represents our estimate of potential punitive damage exposure under Texas law. In addition, the court could award up to $13 million in attorneys fees.

  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 action 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 requested that the court allow the lawsuits to proceed as class actions and sought legal and equitable relief in an unspecified amount. On September 28, 2006, the court granted our and the other defendants’ joint motion to dismiss the class action petitions on various grounds. In August 2006, an additional class action case containing substantially identical allegations was filed against the same defendants, including Transco. On October 20, 2006, we filed a motion to dismiss this latest case on the same basis as the motion filed in the earlier cases.

  Wyoming severance taxes

     The Wyoming Department of Audit (DOA) audited the severance tax reporting for our subsidiary Williams Production RMT Company for the production years 2000 through 2002. In August 2006, the DOA assessed additional severance tax and interest for those periods of approximately $3 million. In addition, the DOA notified us of an increase in the taxable value of our interests for ad valorem tax purposes, which is estimated to result in additional taxes of approximately $2 million, including interest. We dispute the DOA’s interpretation of the statutory obligation and have appealed this assessment to the Wyoming State Board of Equalization. If the DOA prevails in its interpretation of our obligation and applies the same basis of assessment to subsequent periods, it is reasonably possible that we could owe a total of approximately $21 to $24 million in taxes and interest from 2000 through September 30, 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.

     We sold a natural gas liquids pipeline system in 2002, and in July 2006, the purchaser of that system filed its complaint against us and our subsidiaries in state court in Houston, Texas. The purchaser alleges that we breached certain warranties under the purchase and sale agreement and seeks an unspecified amount of damages and our specific performance under certain guarantees. On September 1, 2006, we filed our answer to the purchaser’s complaint denying all liability. The Texas court has denied our request to stay further proceedings against us pending the resolution of our prior suit filed against the purchaser in Delaware state court regarding the same matters.

     At September 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.

Notes (Continued)

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 September 30, 2006, Power’s estimated committed payments under these contracts range from approximately $87 million to $424 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 $5.6 billion.

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 $46 million at September 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 September 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 September 30, 2006.

Notes (Continued)

     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 managing directors for legal fees and potential losses that might result from this litigation. Claims against these former managing directors have been settled and dismissed after payments on their behalf by directors and officers insurers. Some unresolved issues remain between us and these insurers, but no amounts have been accrued for any potential liability.

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

Note 12. Comprehensive Income (Loss)

     Comprehensive income (loss) is as follows:

		Three months ended								Nine months ended
		September 30,								September 30,
		2006				2005				2006				2005
		(Millions)								(Millions)
Net income		$	106.2			$	4.4			$	162.1			$	246.8
Other comprehensive income (loss):
Unrealized gains (losses) on derivative instruments			130.7				(390.3	)			364.9				(663.2	)
Net reclassification into earnings of derivative instrument losses			77.5				65.2				211.8				187.7
Foreign currency translation adjustments			.4				14.7				10.7				9.6
Minimum pension liability adjustment			—				.8				(.3	)			.8
Other comprehensive income (loss) before taxes			208.6				(309.6	)			587.1				(465.1	)
Income tax (provision) benefit on other comprehensive income (loss)			(79.7	)			124.4				(220.6	)			181.9
Other comprehensive income (loss)			128.9				(185.2	)			366.5				(283.2	)
Comprehensive income (loss)		$	235.1			$	(180.8	)		$	528.6			$	(36.4	)

     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 nine months ending September 30, 2006, include net unrealized gains on forward power purchases and sales of approximately $114 million, net unrealized gains on forward natural gas purchases and sales of approximately $261 million, and net unrealized losses on forward natural gas liquids sales of approximately $10 million. Unrealized gains (losses) on derivative instruments for the three and nine months ending September 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 have entered 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.

Notes (Continued)

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.

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

		Exploration								Midstream
		&				Gas				Gas &
		Production				Pipeline				Liquids				Power				Other				Eliminations				Total
		(Millions)
Three months ended September 30, 2006
Segment revenues:
External		$	(54.5	)		$	331.6			$	1,104.1			$	1,916.5			$	2.3			$	—			$	3,300.0
Internal			425.6				2.6				12.9				187.6				4.1				(632.8	)			—
Total revenues		$	371.1			$	334.2			$	1,117.0			$	2,104.1			$	6.4			$	(632.8	)		$	3,300.0
Segment profit (loss)		$	144.5			$	109.0			$	212.2			$	(69.7	)		$	(.2	)		$				$	395.8
Less:
Equity earnings			5.6				9.2				7.3				7.6				.2				—				29.9
Income from investments			—				.5				—				—				—				—				.5
Segment operating income (loss)		$	138.9			$	99.3			$	204.9			$	(77.3	)		$	(.4	)		$	—				365.4
General corporate expenses																											(35.0	)
Securities litigation settlement and related costs																											(3.4	)
Consolidated operating income																										$	327.0
Three months ended September 30, 2005
Segment revenues:
External		$	(52.0	)		$	344.3			$	744.5			$	2,043.4			$	2.1			$	—			$	3,082.3
Internal			370.4				1.5				10.2				199.5				4.2				(585.8	)			—
Total revenues		$	318.4			$	345.8			$	754.7			$	2,242.9			$	6.3			$	(585.8	)		$	3,082.3
Segment profit (loss)		$	158.8			$	161.1			$	121.1			$	(226.4	)		$	(10.1	)		$	—			$	204.5
Less:
Equity earnings (losses)			5.8				17.0				3.2				1.0				(9.4	)			—				17.6
Segment operating income (loss)		$	153.0			$	144.1			$	117.9			$	(227.4	)		$	(0.7	)		$	—				186.9
General corporate expenses																											(42.8	)
Consolidated operating income																										$	144.1