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

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

Commission file number 1-4174

THE WILLIAMS COMPANIES, INC.

(Exact name of registrant as specified in its charter)

DELAWARE		73-0569878
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
ONE WILLIAMS CENTER, TULSA, OKLAHOMA		74172
(Address of principal executive offices)		(Zip Code)

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

NO CHANGE

     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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes o No

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
				(Do not check if a smaller reporting company)

     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 May 2, 2011
Common Stock, $1 par value		588,146,154 Shares

 

 

The Williams Companies, Inc.
Index

		Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Operations — Three Months Ended March 31, 2011 and 2010			3
Consolidated Balance Sheet — March 31, 2011 and December 31, 2010			4
Consolidated Statement of Changes in Equity — Three Months Ended March 31, 2011 and 2010			5
Consolidated Statement of Cash Flows — Three Months Ended March 31, 2011 and 2010			6
Notes to Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			27
Item 3. Quantitative and Qualitative Disclosures About Market Risk			47
Item 4. Controls and Procedures			49
Part II. Other Information			49
Item 1. Legal Proceedings			49
Item 1A. Risk Factors			50
Item 6. Exhibits			51
EX-12
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

     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 forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. 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 that 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,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

	•		Amounts and nature of future capital expenditures;
	•		Expansion and growth of our business and operations;
	•		Financial condition and liquidity;
	•		Business strategy;
	•		Estimates of proved gas and oil reserves;
	•		Reserve potential;
	•		Development drilling potential;
	•		Cash flow from operations or results of operations;
	•		Seasonality of certain business segments;
	•		Natural gas, natural gas liquids, and crude oil 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 report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

	•		Availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future natural gas and oil reserves), market demand, volatility of prices, and the availability and cost of capital;
	•		Inflation, interest rates, fluctuation in foreign exchange, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
	•		The strength and financial resources of our competitors;
	•		Development of alternative energy sources;
	•		The impact of operational and development hazards;
	•		Costs of, changes in, or the results of laws, government regulations (including climate change legislation and/or potential additional regulation of drilling and completion of wells), environmental liabilities, litigation, and rate proceedings;
	•		Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
	•		Changes in maintenance and construction costs;
	•		Changes in the current geopolitical situation;
	•		Our exposure to the credit risk of our customers;
	•		Risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;
	•		Risks associated with future weather conditions;
	•		Acts of terrorism;
	•		Additional risks described in our filings with the Securities and Exchange Commission.

     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 to 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 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2010, and Part II, Item 1A. Risk Factors of this Form 10-Q.

The Williams Companies, Inc.

		Three months ended March 31,
(Millions, except per-share amounts)		2011				2010
Revenues:
Williams Partners		$	1,579			$	1,490
Exploration & Production			989				1,157
Midstream Canada & Olefins			316				272
Other			6				6
Intercompany eliminations			(315	)			(334	)
Total revenues			2,575				2,591
Segment costs and expenses:
Costs and operating expenses			1,908				1,917
Selling, general, and administrative expenses			137				111
Other (income) expense — net			(1	)			(1	)
Total segment costs and expenses			2,044				2,027
General corporate expenses			51				85
Operating income (loss):
Williams Partners			412				398
Exploration & Production			45				148
Midstream Canada & Olefins			74				20
Other			—				(2	)
General corporate expenses			(51	)			(85	)
Total operating income (loss)			480				479
Interest accrued			(158	)			(164	)
Interest capitalized			9				17
Investing income — net			51				39
Early debt retirement costs			—				(606	)
Other income (expense) — net			4				(7	)
Income (loss) from continuing operations before income taxes			386				(242	)
Provision (benefit) for income taxes			(6	)			(94	)
Income (loss) from continuing operations			392				(148	)
Income (loss) from discontinued operations			(8	)			2
Net income (loss)			384				(146	)
Less: Net income attributable to noncontrolling interests			63				47
Net income (loss) attributable to The Williams Companies, Inc.		$	321			$	(193	)
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations		$	329			$	(195	)
Income (loss) from discontinued operations			(8	)			2
Net income (loss)		$	321			$	(193	)
Basic earnings (loss) per common share:
Income (loss) from continuing operations		$	.56			$	(.33	)
Income (loss) from discontinued operations			(.01	)			—
Net income (loss)		$	.55			$	(.33	)
Weighted-average shares (thousands)			586,977				583,929
Diluted earnings (loss) per common share:
Income (loss) from continuing operations		$	.55			$	(.33	)
Income (loss) from discontinued operations			(.01	)			—
Net income (loss)		$	.54			$	(.33	)
Weighted-average shares (thousands)			596,567				583,929
Cash dividends declared per common share		$	.125			$	.11

See accompanying notes.

The Williams Companies, Inc.

		March 31,				December 31,
(Dollars in millions, except per-share amounts)		2011				2010
ASSETS
Current assets:
Cash and cash equivalents		$	923			$	795
Accounts and notes receivable (net of allowance of $18 at March 31, 2011 and $15 at December 31, 2010)			850				859
Inventories			264				302
Derivative assets			301				400
Other current assets and deferred charges			167				174
Total current assets			2,505				2,530
Investments			1,381				1,344
Property, plant, and equipment, at cost			30,816				30,365
Accumulated depreciation, depletion, and amortization			(10,475	)			(10,144	)
Property, plant, and equipment — net			20,341				20,221
Derivative assets			167				173
Other assets and deferred charges			689				704
Total assets		$	25,083			$	24,972
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	913			$	918
Accrued liabilities			872				1,002
Derivative liabilities			141				146
Long-term debt due within one year			532				508
Total current liabilities			2,458				2,574
Long-term debt			8,577				8,600
Deferred income taxes			3,448				3,448
Derivative liabilities			158				143
Other liabilities and deferred income			1,563				1,588
Contingent liabilities and commitments (Note 11)
Equity:
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 622 million shares issued at March 31, 2011 and 620 million shares issued at December 31, 2010)			622				620
Capital in excess of par value			8,302				8,269
Retained earnings (deficit)			(230	)			(478	)
Accumulated other comprehensive income (loss)			(116	)			(82	)
Treasury stock, at cost (35 million shares of common stock)			(1,041	)			(1,041	)
Total stockholders’ equity			7,537				7,288
Noncontrolling interests in consolidated subsidiaries			1,342				1,331
Total equity			8,879				8,619
Total liabilities and equity		$	25,083			$	24,972

See accompanying notes.

The Williams Companies, Inc.

		Three months ended March 31,
		2011												2010
		The Williams				Noncontrolling								The Williams				Noncontrolling
		Companies, Inc.				Interests				Total				Companies, Inc.				Interests				Total
		(Millions)
Beginning balance		$	7,288			$	1,331			$	8,619			$	8,447			$	572			$	9,019
Comprehensive income (loss):
Net income (loss)			321				63				384				(193	)			47				(146	)
Other comprehensive income (loss), net of tax:
Net change in cash flow hedges			(62	)			—				(62	)			147				2				149
Foreign currency translation adjustments			22				—				22				19				—				19
Pension and other postretirement benefits — net			6				—				6				5				—				5
Total other comprehensive income (loss)			(34	)			—				(34	)			171				2				173
Total comprehensive income (loss)			287				63				350				(22	)			49				27
Cash dividends — common stock			(73	)			—				(73	)			(64	)			—				(64	)
Dividends and distributions to noncontrolling interests			—				(52	)			(52	)			—				(32	)			(32	)
Stock-based compensation, net of tax			35				—				35				12				—				12
Change in Williams Partners L.P. ownership interest (Note 2)			—				—				—				(454	)			454				—
Ending balance		$	7,537			$	1,342			$	8,879			$	7,919			$	1,043			$	8,962

See accompanying notes.

The Williams Companies, Inc.

		Three months ended March 31,
(Millions)		2011				2010
OPERATING ACTIVITIES:
Net income (loss)		$	384			$	(146	)
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, depletion, and amortization			381				361
Provision (benefit) for deferred income taxes			(10	)			29
Provision for loss on investments, property and other assets			31				4
Amortization of stock-based awards			14				14
Early debt retirement costs			—				606
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable			6				2
Inventories			38				—
Margin deposits and customer margin deposits payable			(19	)			11
Other current assets and deferred charges			28				21
Accounts payable			46				(13	)
Accrued liabilities			(65	)			(280	)
Changes in current and noncurrent derivative assets and liabilities			17				(8	)
Other, including changes in noncurrent assets and liabilities			(40	)			16
Net cash provided by operating activities			811				617
FINANCING ACTIVITIES:
Proceeds from long-term debt			75				3,749
Payments of long-term debt			(75	)			(3,407	)
Dividends paid			(73	)			(64	)
Dividends and distributions paid to noncontrolling interests			(52	)			(32	)
Payments for debt issuance costs			—				(65	)
Premiums paid on early debt retirements			—				(574	)
Other — net			21				(12	)
Net cash provided (used) by financing activities			(104	)			(405	)
INVESTING ACTIVITIES:
Capital expenditures*			(526	)			(428	)
Purchases of investments/advances to affiliates			(42	)			(13	)
Other — net			(11	)			6
Net cash used by investing activities			(579	)			(435	)
Increase (decrease) in cash and cash equivalents			128				(223	)
Cash and cash equivalents at beginning of period			795				1,867
Cash and cash equivalents at end of period		$	923			$	1,644
______________
*   Increases to property, plant, and equipment		$	(482	)		$	(410	)
Changes in related accounts payable and accrued liabilities			(44	)			(18	)
Capital expenditures		$	(526	)		$	(428	)

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 March 31, 2011, results of operations, changes in equity, and cash flows for the three months ended March 31, 2011 and 2010.

     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.

     On February 16, 2011, we announced that our Board of Directors approved our reorganization plan to divide our business into two separate, publicly traded corporations. On April 29, 2011, our wholly owned subsidiary, WPX Energy, Inc. (WPX), filed a registration statement with the SEC with respect to an initial public offering of its equity securities. This is the first step in our reorganization plan, which calls for a separation of our exploration and production business through an initial public offering and a tax-free spin-off of our remaining interest in WPX to our shareholders. We retain the discretion to determine whether and when to complete these transactions.

Note 2. Basis of Presentation

     Beginning with the first quarter of 2011, we changed our segment reporting structure to present our Canadian midstream and domestic olefins operations as a separate segment, Midstream Canada & Olefins. This change reflects the expected growth in this business and our chief operating decision maker’s increased focus on these operations, which were previously reported within Other. Prior periods have been recast to reflect this revised segment presentation.

     Our operations are located principally in the United States and are organized into the following reporting segments: Williams Partners, Exploration & Production and Midstream Canada & Olefins. All remaining business activities are included in Other.

     Williams Partners consists of our consolidated master limited partnership, Williams Partners L.P. (WPZ) and includes our gas pipeline and domestic midstream businesses. The gas pipeline businesses include 100 percent of Transcontinental Gas Pipe Line Company, LLC (Transco), 100 percent of Northwest Pipeline GP (Northwest Pipeline), and 24.5 percent of Gulfstream Natural Gas System, L.L.C. (Gulfstream). WPZ’s midstream operations are composed of significant, large-scale operations in the Rocky Mountain and Gulf Coast regions, operations in Pennsylvania’s Marcellus Shale region, and various equity investments in domestic processing, fractionation, and natural gas liquid (NGL) transportation assets. WPZ’s midstream assets also include substantial operations and investments in the Four Corners and Gulf Coast regions, as well as an NGL fractionator and storage facilities near Conway, Kansas.

     Exploration & Production includes the natural gas development, production and gas management activities, with operations primarily in the Rocky Mountain and Mid-Continent regions of the United States, natural gas development activities in the northeastern portion of the United States, oil and natural gas interests in South America, and oil development activities in the northern United States. The gas management activities include procuring fuel and shrink gas for our midstream businesses and providing marketing to third parties, such as producers. Additionally, gas management activities include managing various natural gas related contracts such as transportation, storage, and related hedges.

Notes (Continued)

     Our Midstream Canada & Olefins segment includes our oil sands off-gas processing plant near Fort McMurray, Alberta, our NGL/olefin fractionation facility and butylene/butane splitter facility at Redwater, Alberta, our NGL light-feed olefins cracker in Geismar, Louisiana along with associated ethane and propane pipelines, and our refinery grade splitter in Louisiana.

     Other includes other business activities that are not operating segments, primarily a 25.5 percent interest in Gulfstream, as well as corporate operations.

     During fourth-quarter 2010, we contributed a business represented by certain gathering and processing assets in Colorado’s Piceance basin to WPZ. The transaction was accounted for as a combination of entities under common control whereby the assets and liabilities sold were recorded by WPZ at their historical amounts. The operations of this business and the related assets and liabilities were previously reported through our Exploration & Production segment, however they are now reported in our Williams Partners segment. Prior period segment disclosures have been recast for this transaction.

Master Limited Partnership

     At March 31, 2011, we own approximately 75 percent of the interests in WPZ, including the interests of the general partner, which is wholly owned by us, and incentive distribution rights.

     WPZ is self funding and maintains separate lines of bank credit and cash management accounts. Cash distributions from WPZ to us, including any associated with our incentive distribution rights, occur through the normal partnership distributions from WPZ to all partners.

     The change in WPZ ownership between us and the noncontrolling interests as a result of our February 2010 strategic restructuring was accounted for as an equity transaction and resulted in a $454 million decrease to capital in excess of par value and a corresponding increase to noncontrolling interest in consolidated subsidiaries.

     For the first quarter of 2010, this amount related to the change between our ownership interest and the noncontrolling interests resulting from the restructuring was previously reported as $800 million. During the third quarter of 2010, we determined that this amount was incorrect. This error resulted in a $346 million overstatement of noncontrolling interests in consolidated subsidiaries and a $346 million understatement of capital in excess of par value in the first and second quarter. The error did not impact total equity, key financial covenants, any earnings or cash flow measures or any other key internal measures. First quarter 2010 amounts have been adjusted for the correction in the Consolidated Statement of Changes in Equity.

Discontinued operations

     The accompanying consolidated financial statements and notes reflect the results of operations and financial position of Exploration & Production’s Arkoma basin operations as discontinued operations for all periods. (See Note 3.)

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

Notes (Continued)

Note 3. Discontinued Operations

Summarized Results of Discontinued Operations

		Three months ended March 31,
		2011				2010
		(Millions)
Revenues		$	3			$	5
Income (loss) from discontinued operations before impairment and income taxes		$	(2	)		$	4
Impairment			(9	)			—
(Provision) benefit for income taxes			3				(2	)
Income (loss) from discontinued operations		$	(8	)		$	2

     Impairment in 2011 reflects a write-down to an estimate of fair value less costs to sell the assets of our Arkoma basin operations that were classified as held for sale as of March 31, 2011. This nonrecurring fair value measurement, which falls within Level 3 of the fair value hierarchy, was based on a probability-weighted discounted cash flow analysis that included offers we have received on the assets.

     The assets of our discontinued operations comprise significantly less than 0.5 percent of our total consolidated assets as of March 31, 2011, and December 31, 2010, and are reported primarily within other current assets and deferred charges and other assets and deferred charges, respectively, on our Consolidated Balance Sheet. Liabilities of our discontinued operations are insignificant for these periods.

Note 4. Asset Sales and Other Accruals

     Other (income) expense — net within segment costs and expenses in 2011 includes $10 million related to the reversal of project feasibility costs from expense to capital at Williams Partners, associated with a natural gas pipeline expansion project, upon determining that the related project was probable of development. These costs will be included in the capital costs of the project, which we believe are probable of recovery through the project rates.

     Additional Items

     We completed a strategic restructuring transaction in the first quarter of 2010 that involved significant debt issuances, retirements and amendments. We incurred significant costs related to these transactions, as follows:

•

$606 million of early debt retirement costs consisting primarily of cash premiums;

•

$39 million of other transaction costs reflected in general corporate expenses, of which $4 million is attributable to noncontrolling interests;

•

$4 million of accelerated amortization of debt costs related to the amendments of credit facilities, reflected in other income (expense) — net below operating income (loss).

     We recognized an $11 million gain in the first quarter of 2011 on the 2010 sale of our interest in Accroven SRL, reflecting the receipt of the first quarterly payment, which was originally due from the buyer in October 2010. This gain is reflected within investing income — net at Other. Payments are recognized as income upon receipt until such point future collections are reasonably assured.

Note 5. Provision (Benefit) for Income Taxes

     The provision (benefit) for income taxes includes:

Notes (Continued)

		Three months ended March 31,
		2011				2010
		(Millions)
Current:
Federal		$	17			$	(113	)
State			1				(14	)
Foreign			(18	)			5
			—				(122	)
Deferred:
Federal			(8	)			23
State			1				3
Foreign			1				2
			(6	)			28
Total provision (benefit)		$	(6	)		$	(94	)

     The effective income tax rate on the total benefit for the three months ended March 31, 2011, is less than the federal statutory rate primarily due to federal settlements, an international revised assessment and the impact of nontaxable noncontrolling interests, partially offset by the effect of state income taxes.

     The effective income tax rate on the total benefit for the three months ended March 31, 2010, is greater than the federal statutory rate primarily due to the effect of state income taxes and the impact of nontaxable noncontrolling interests, partially offset by the reduction of tax benefits on the Medicare Part D federal subsidy due to enacted healthcare legislation.

     During the first quarter of 2011, we finalized settlements for 1997 through 2008 on certain contested matters with the Internal Revenue Service (IRS) and also received a revised assessment on an international matter. These settlements and revised assessment resulted in a tax benefit of approximately $124 million during the first quarter of 2011. As a result of these settlements and revised assessment, we have decreased our unrecognized tax benefits by approximately $62 million. We anticipate making approximately $140 million to $145 million of cash payments (net of refunds) to taxing authorities related to these items in 2011.

      During the next twelve months, we do not expect ultimate resolution of any uncertain tax position will result in a significant increase or decrease of our unrecognized tax benefit.

Notes (Continued)

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

		Three months ended March 31,
		2011				2010
		(Dollars in millions, except per-share
		amounts; shares in thousands)
Income (loss) from continuing operations attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share (1)		$	329			$	(195	)
Basic weighted-average shares			586,977				583,929
Effect of dilutive securities:
Nonvested restricted stock units			4,125				—
Stock options			3,464				—
Convertible debentures			2,001				—
Diluted weighted-average shares			596,567				583,929
Earnings (loss) per common share from continuing operations:
Basic		$	.56			$	(.33	)
Diluted		$	.55			$	(.33	)

     For the three months ended March 31, 2010, 3.3 million weighted-average nonvested restricted stock units and 3.2 million weighted-average stock options have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to The Williams Companies, Inc.

     Additionally, for the three months ended March 31, 2010, 2.3 million weighted-average shares related to the assumed conversion of our convertible debentures, as well as the related interest, net of tax, have been excluded from the computation of diluted earnings per common share. Inclusion of these shares would have an antidilutive effect on the diluted earnings per common share. We estimate that if income (loss) from continuing operations attributable to The Williams Companies, Inc. available to common stockholders was $54 million of income for the three months ended March 31, 2010, then these shares would become dilutive.

     The table below includes information related to stock options that were outstanding at March 31 of each respective year but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the first quarter weighted-average market price of our common shares.

		March 31,
		2011				2010
Options excluded (millions)			3.0				2.4
Weighted-average exercise price of options excluded		$	31.50			$	32.40
Exercise price ranges of options excluded		$	28.30 - $40.51			$	22.25 - $40.51
First quarter weighted-average market price		$	28.27			$	22.18

Notes (Continued)

Note 7. Employee Benefit Plans

     Net periodic benefit expense is as follows:

										Other Postretirement
		Pension Benefits								Benefits
		Three months ended March 31,								Three months ended March 31,
		2011				2010				2011				2010
		(Millions)
Components of net periodic benefit expense:
Service cost		$	10			$	8			$	1			$	1
Interest cost			17				16				4				4
Expected return on plan assets			(19	)			(18	)			(3	)			(3	)
Amortization of prior service credit			—				—				(3	)			(3	)
Amortization of net actuarial loss			9				9				1				—
Net periodic benefit expense (income)		$	17			$	15			$	—			$	(1	)

     During the three months ended March 31, 2011, we contributed $17 million to our pension plans and $4 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $51 million to our pension plans and approximately $12 million to our other postretirement benefit plans in the remainder of 2011.

Note 8. Inventories

		March 31,				December 31,
		2011				2010
		(Millions)
Natural gas liquids and olefins		$	97			$	87
Natural gas in underground storage			52				93
Materials, supplies, and other			115				122
		$	264			$	302

Note 9. Fair Value Measurements

     The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis.

		March 31, 2011																December 31, 2010
		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
		(Millions)																(Millions)
Assets:
Energy derivatives		$	58			$	407			$	3			$	468			$	96			$	475			$	2			$	573
ARO Trust investments (see Note 10)			38				—				—				38				40				—				—				40
Total assets		$	96			$	407			$	3			$	506			$	136			$	475			$	2			$	613
Liabilities:
Energy derivatives		$	54			$	242			$	3			$	299			$	78			$	210			$	1			$	289
Total liabilities		$	54			$	242			$	3			$	299			$	78			$	210			$	1			$	289

     Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) contracts. Exchange-traded contracts include futures, swaps, and options. OTC contracts include forwards, swaps and options.

Notes (Continued)

     The instruments included in our Level 1 measurements primarily consist of energy derivatives that are exchange-traded and a portfolio of mutual funds. Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets.

     The instruments included in our Level 2 measurements consist primarily of OTC instruments. Forward, swap, and option contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of production from our Exploration & Production segment, are structured as costless collars and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Significant inputs into our Level 2 valuations include commodity prices, implied volatility by location, and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

     The instruments in our Level 3 measurements primarily consist of natural gas index transactions that are used to manage the physical requirements of our Exploration & Production segment. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 because these inputs have a significant impact on the measurement of fair value. As the fair value of natural gas index transactions is primarily driven by the typically nominal differential transacted and the market price, these transactions do not have a material impact on our results of operations or liquidity.

     Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with more than 99 percent of the value of our derivatives portfolio expiring in the next 21 months. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes and documented on a monthly basis.

     Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1 and Level 2 occurred during the period ended March 31, 2011 or 2010. During the period ended March 31, 2011, certain NGL swaps that originated during the first quarter of 2011 were transferred from Level 3 to Level 2. Prior to March 31, 2011, these swaps were considered Level 3 due to a lack of observable third-party market quotes. Due to an increase in exchange-traded transactions and greater visibility from OTC trading, we transferred these instruments to Level 2.

     The following table presents a reconciliation of changes in the fair value of our net energy derivatives classified as Level 3 in the fair value hierarchy.

Level 3 Fair Value Measurements Using Significant Unobservable Inputs

		Three months ended March 31,
		2011				2010
		(Millions)
Beginning balance		$	1			$	2
Realized and unrealized gains (losses):
Included in income (loss) from continuing operations			(1	)			—
Included in other comprehensive income (loss)			(1	)			4
Settlements			—				(1	)
Transfers into Level 3			—				—
Transfers out of Level 3			1				—
Ending balance		$	—			$	5
Unrealized gains (losses) included in income (loss) from continuing operations relating to instruments still held at March 31		$	(2	)		$	—

Notes (Continued)

     Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues or costs and operating expenses in our Consolidated Statement of Operations.

Note 10. Financial Instruments, Derivatives, Guarantees, and Concentration of Credit Risk

Financial Instruments

  Fair-value methods

     We use the following methods and assumptions in estimating our fair-value disclosures for financial instruments:

     Cash and cash equivalents and restricted cash: The carrying amounts reported in the Consolidated Balance Sheet approximate fair value due to the short-term maturity of these instruments. Current and noncurrent restricted cash is included in other current assets and deferred charges and other assets and deferred charges, respectively, in the Consolidated Balance Sheet, based on the term of the related restriction.

     ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its 2008 rate case settlement, into an external trust (ARO Trust) specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of mutual funds that are reported at fair value in other assets and deferred charges in the Consolidated Balance Sheet and are classified as available-for-sale. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

     Long-term debt: The fair value of our publicly traded long-term debt is determined using indicative period-end traded bond market prices. At both March 31, 2011 and December 31, 2010, approximately 100 percent of our long-term debt was publicly traded.

     Guarantee: The guarantee represented in the following table consists of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation. To estimate the fair value of the guarantee, the estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rates are published by Moody’s Investors Service. Guarantees, if recognized, are included in accrued liabilities in the Consolidated Balance Sheet.

     Other: Includes current and noncurrent notes receivable, margin deposits, customer margin deposits payable, and cost-based investments.

     Energy derivatives: Energy derivatives include futures, forwards, swaps, and options. These are carried at fair value in the Consolidated Balance Sheet. See Note 9 for a discussion of the valuation of our energy derivatives.

  Carrying amounts and fair values of our financial instruments

		March 31, 2011								December 31, 2010
		Carrying								Carrying
Asset (Liability)		Amount				Fair Value				Amount				Fair Value
		(Millions)
Cash and cash equivalents		$	923			$	923			$	795			$	795
Restricted cash (current and noncurrent)		$	27			$	27			$	28			$	28
ARO Trust investments		$	38			$	38			$	40			$	40
Long-term debt, including current portion (a)		$	(9,105	)		$	(10,101	)		$	(9,104	)		$	(9,990	)
Guarantee		$	(35	)		$	(33	)		$	(35	)		$	(34	)
Other		$	(5	)		$	(6	)(b)		$	(23	)		$	(25	)(b)
Net energy derivatives:
Energy commodity cash flow hedges		$	168			$	168			$	266			$	266
Other energy derivatives		$	1			$	1			$	18			$	18

Notes (Continued)

Energy Commodity Derivatives

  Risk management activities

     We are exposed to market risk from changes in energy commodity prices within our operations. We manage this risk on an enterprise basis and may utilize derivatives to manage our exposure to the variability in expected future cash flows from forecasted purchases and sales of natural gas and NGLs attributable to commodity price risk. Certain of these derivatives utilized for risk management purposes have been designated as cash flow hedges, while other derivatives have not been designated as cash flow hedges or do not qualify for hedge accounting despite hedging our future cash flows on an economic basis.

     We produce, buy, and sell natural gas at different locations throughout the United States. We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity agreements. To reduce exposure to a decrease in revenues or margins from fluctuations in natural gas market prices, we enter into natural gas futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of natural gas. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Those designated as cash flow hedges are expected to be highly effective in 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. Our financial option contracts are either purchased options or a combination of options that comprise a net purchased option or a zero-cost collar. Our designation of the hedging relationship and method of assessing effectiveness for these option contracts are generally such that the hedging relationship is considered perfectly effective and no ineffectiveness is recognized in earnings. Hedges for storage contracts have not been designated as cash flow hedges, despite economically hedging the expected cash flows generated by those agreements.

     We produce and sell NGLs and olefins at different locations throughout North America. We also buy natural gas to satisfy the required fuel and shrink needed to generate NGLs and olefins. To reduce exposure to a decrease in revenues from fluctuations in NGL market prices or increases in costs and operating expenses from fluctuations in natural gas and NGL market prices, we may enter into NGL or natural gas swap agreements, financial forward contracts, and financial option contracts to mitigate the price risk on forecasted sales of NGLs and purchases of natural gas and NGLs. Those designated as cash flow hedges are expected to be highly effective in 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.

  Other activities

     We also enter into energy commodity derivatives for other than risk management purposes, including managing certain remaining legacy natural gas contracts and positions from our former power business and providing services to third parties. These legacy natural gas contracts include substantially offsetting positions and have an insignificant net impact on earnings.

  Volumes

     Our energy commodity derivatives are comprised of both contracts to purchase the commodity (long positions) and contracts to sell the commodity (short positions). Derivative transactions are categorized into four types:

•

Central hub risk: Includes physical and financial derivative exposures to Henry Hub for natural gas, West Texas Intermediate for crude oil, and Mont Belvieu for NGLs;

•

Basis risk: Includes physical and financial derivative exposures to the difference in value between the central hub and another specific delivery point;

Notes (Continued)

•

Index risk: Includes physical derivative exposure at an unknown future price;

•

Options: Includes all fixed price options or combination of options (collars) that set a floor and/or ceiling for the transaction price of a commodity.

Fixed price swaps at locations other than the central hub are classified as both central hub risk and basis risk instruments to represent their exposure to overall market conditions (central hub risk) and specific location risk (basis risk).

     The following table depicts the notional quantities of the net long (short) positions in our commodity derivatives portfolio as of March 31, 2011. Natural gas is presented in millions of British Thermal Units (MMBtu), NGLs are presented in gallons, and oil is presented in barrels. The volumes for options represent at location zero-cost collars and present one side of the short position. The net index position for Exploration & Production includes certain positions on behalf of other segments.

				Unit of		Central Hub				Basis				Index
Derivative Notional Volumes				Measure		Risk				Risk				Risk				Options
Designated as Hedging Instruments
Exploration & Production		Risk Management		MMBtu			(262,335,000	)			(262,335,000	)							(75,625,000	)
Exploration & Production		Risk Management		Barrels			(3,701,250	)
Williams Partners		Risk Management		MMBtu			8,250,000				7,562,500
Williams Partners		Risk Management		Gallons			(2,280,000	)
Not Designated as Hedging Instruments
Exploration & Production		Risk Management		MMBtu			(6,542,400	)			(17,452,400	)			(30,877,696	)
Williams Partners		Risk Management		Gallons			(50,000	)
Midstream Canada & Olefins		Risk Management		Gallons			(20,000	)
Exploration & Production		Other		MMBtu			(1,500	)			(226,500	)

  Fair values and gains (losses)

     The following table presents the fair value of energy commodity derivatives. Our derivatives are presented as separate line items in our Consolidated Balance Sheet as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.

		March 31, 2011								December 31, 2010
		Assets				Liabilities				Assets				Liabilities
		(Millions)
Designated as hedging instruments		$	233			$	65			$	288			$	22
Not designated as hedging instruments:
Legacy natural gas contracts from former power business			223				224				186				187
All other			12				10				99				80
Total derivatives not designated as hedging instruments			235				234				285				267
Total derivatives		$	468			$	299			$	573			$	289

Notes (Continued)

     The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in AOCI, revenues, or costs and operating expenses.

		Three months ended March 31,
		2011				2010				Classification
		(Millions)
Net gain (loss) recognized in other comprehensive income (loss) (effective portion)		$	(23	)		$	278			AOCI
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion)		$	75			$	25			Revenues or Costs and Operating Expenses
Gain (loss) recognized in income (ineffective portion)		$	—			$	5			Revenues or Costs and Operating Expenses

     There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness or as a result of reclassifications to earnings following the discontinuance of any cash flow hedges.

     The following table presents pre-tax gains and losses for our energy commodity derivatives not designated as hedging instruments.

		Three months ended March 31,
		2011				2010
		(Millions)
Revenues		$	2			$	26
Costs and operating expenses			—				—
Net gain		$	2			$	26

     The cash flow impact of our derivative activities is presented in the Consolidated Statement of Cash Flows as changes in current and noncurrent derivative assets and liabilities.

  Credit-risk-related features

     Certain of our derivative contracts contain credit-risk-related provisions that would require us, in certain circumstances, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investors Service. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability. Additionally, Exploration & Production has an unsecured credit agreement with certain banks related to hedging activities. We are not required to provide collateral support for net derivative liability positions under the credit agreement as long as the value of Exploration & Production’s domestic natural gas reserves, as determined under the provisions of the agreement, exceeds by a specified amount certain of its obligations including any outstanding debt and the aggregate out-of-the-money position on hedges entered into under the credit agreement.

     As of March 31, 2011, we did not have any collateral posted to derivative counterparties to support the aggregate fair value of our net derivative liability position (reflecting master netting arrangements in place with certain counterparties) of $26 million, which includes a reduction of significantly less than $1 million to our liability balance for our own nonperformance risk. At December 31, 2010, we had collateral totaling $8 million posted to

Notes (Continued)

derivative counterparties, all of which was in the form of letters of credit, to support the aggregate fair value of our net derivative liability position (reflecting master netting arrangements in place with certain counterparties) of $36 million, which included a reduction of less than $1 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was $26 million and $29 million at March 31, 2011 and December 31, 2010, respectively.

  Cash flow hedges

     Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in AOCI and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. As of March 31, 2011, we have hedged portions of future cash flows associated with anticipated energy commodity purchases and sales for up to two years. Based on recorded values at March 31, 2011, $99 million of net gains (net of income tax provision of $60 million) will be reclassified into earnings within the next year. These recorded values are based on market prices of the commodities as of March 31, 2011. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized within the next year will likely differ from these values. These gains or losses are expected to substantially offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.

Guarantees

     We are required by our revolving credit agreements to indemnify lenders for any taxes required to be withheld from payments due to the lenders and for any tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. 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 and have no current expectation of a future claim.

     We have provided a guarantee in the event of nonpayment by our previously owned communications subsidiary, WilTel, on a certain lease performance obligation that extends through 2042. The maximum potential exposure is approximately $39 million at March 31, 2011 and December 31, 2010. Our exposure declines systematically throughout the remaining term of WilTel’s obligation. The carrying value of the guarantee included in accrued liabilities on the Consolidated Balance Sheet is $35 million at March 31, 2011 and December 31, 2010.

     At March 31, 2011, we do not expect these guarantees to have a material impact on our future liquidity or financial position. However, if we are required to perform on these guarantees in the future, it may have a material adverse effect on our results of operations.

Concentration of Credit Risk

  Derivative assets and liabilities

     We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements, and guarantees of payment by credit worthy parties. The gross credit exposure from our derivative contracts as of March 31, 2011, is summarized as follows:

Notes (Continued)

		Investment
Counterparty Type		Grade(a)				Total
		(Millions)
Gas and electric utilities		$	2			$	2
Energy marketers and traders			—				142
Financial institutions			324				324
		$	326				468
Credit reserves							—
Gross credit exposure from derivatives						$	468

     We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts. The net credit exposure from our derivatives as of March 31, 2011, excluding collateral support discussed below, is summarized as follows:

		Investment
Counterparty Type		Grade(a)				Total
		(Millions)
Gas and electric utilities		$	2			$	2
Energy marketers and traders			—				1
Financial institutions			192				192
		$	194				195
Credit reserves							—
Net credit exposure from derivatives						$	195

     Our seven largest net counterparty positions represent approximately 96 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Included within this group are counterparty positions, representing 83 percent of our net credit exposure from derivatives, associated with Exploration & Production’s hedging facility. Under certain conditions, the terms of this credit agreement may require the participating financial institutions to deliver collateral support to a designated collateral agent (which is another participating financial institution in the agreement). The level of collateral support required is dependent on whether the net position of the counterparty financial institution exceeds specified thresholds. The thresholds may be subject to prescribed reductions based on changes in the credit rating of the counterparty financial institution.

     At March 31, 2011, the designated collateral agent is not required to hold any collateral support on our behalf under Exploration & Production’s hedging facility. We hold collateral support, which may include cash or letters of credit, of $8 million related to our other derivative positions.

Note 11. Contingent Liabilities

Issues Resulting from California Energy Crisis

     Our former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the Federal Energy Regulatory Commission (FERC). We have entered into settlements with the State of California (State Settlement), major California utilities (Utilities Settlement), and others that substantially resolved each of these issues with these parties.

Notes (Continued)

     Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. We are currently in settlement negotiations with certain California utilities aimed at eliminating or substantially reducing this exposure. If successful, and subject to a final “true-up” mechanism, the settlement agreement would also resolve our collection of accrued interest from counterparties as well as our payment of accrued interest on refund amounts. Thus, as currently contemplated by the parties, the settlement agreement would resolve most, if not all, of our legal issues arising from the 2000-2001 California Energy Crisis. With respect to these matters, amounts accrued are not material to our financial position.

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

Reporting of Natural Gas-Related Information to Trade Publications

     Civil suits based on allegations of manipulating published gas price 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 and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. We expect that the Colorado plaintiffs will appeal, but the appeal cannot occur until the case against the remaining defendant is concluded.

     In the other cases, our joint motions for summary judgment to preclude the plaintiffs’ state law claims based upon federal preemption have been pending since late 2009. If the motions are granted, we expect a final judgment in our favor which the plaintiffs could appeal. If the motions are denied, the current stay of activity would be lifted, class certification would be addressed, and discovery would be completed as the cases proceed towards trial. Because of the uncertainty around these current pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time. However, it is reasonably possible that the ultimate resolution of these items could result in future charges that may be material to our results of operations.

Environmental Matters

  Continuing operations

     Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyl, mercury contamination, and other hazardous substances. These activities have involved the U.S. Environmental Protection Agency (EPA), various state environmental authorities and identification as a potentially responsible party at various Superfund waste disposal sites. At March 31, 2011, we have accrued liabilities of $12 million for these costs. We expect that these costs will be recoverable through rates.

     We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At March 31, 2011, we have accrued liabilities totaling $7 million for these costs.

     In March 2008, the EPA proposed a penalty of $370,000 for alleged violations relating to leak detection and repair program delays at our Ignacio gas plant in Colorado and for alleged permit violations at a compressor station. Tentative settlement has been reached in first-quarter 2011.

     In September 2007, the EPA requested, and our Transco subsidiary later provided, information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of our compliance with the Clean Air Act. On March 28, 2008, the EPA issued notices of violation alleging violations of Clean Air Act requirements at these compressor stations. Transco met with the EPA in May 2008 and submitted our response denying the allegations in June 2008. The EPA has requested additional information pertaining to these compressor stations, most recently in February 2011. In August 2010, the EPA requested and our Transco subsidiary provided, similar information for a compressor station in Maryland.

Notes (Continued)

  Former operations, including operations classified as discontinued

     We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.

•

Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;

•

Former petroleum products and natural gas pipelines;

•

Discontinued petroleum refining facilities;

•

Former exploration and production and mining operations.

     At March 31, 2011, we have accrued environmental liabilities of $31 million related to these matters.

     Actual costs 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. Any incremental amount cannot be reasonably estimated at this time.

     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.

  Environmental matters — general

     The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, and one hour nitrogen dioxide emission limits. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

Other Legal Matters

  Gulf Liquids litigation

     Gulf Liquids contracted with Gulsby Engineering Inc. (Gulsby) and Gulsby-Bay (a joint venture between Gulsby and Bay Ltd.) 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. In 2001, the contractors and sureties filed multiple cases in Louisiana and Texas against Gulf Liquids and us.

     In 2006, at the conclusion of the consolidated trial of the asserted contract and tort claims, the jury returned its actual and punitive damages verdict against us and Gulf Liquids. Based on our interpretation of the jury verdicts, we recorded a charge based on our estimated exposure for actual damages of approximately $68 million plus potential interest of approximately $20 million. In addition, we concluded that it was reasonably possible that any ultimate judgment might have included additional amounts of approximately $199 million in excess of our accrual, which primarily represented our estimate of potential punitive damage exposure under Texas law.

     From May through October 2007, the court entered seven post-trial orders in the case (interlocutory orders) which, among other things, overruled the verdict award of tort and punitive damages as well as any damages against

Notes (Continued)

us. The court also denied the plaintiffs’ claims for attorneys’ fees. On January 28, 2008, the court issued its judgment awarding damages against Gulf Liquids of approximately $11 million in favor of Gulsby and approximately $4 million in favor of Gulsby-Bay. Gulf Liquids, Gulsby, Gulsby-Bay, Bay Ltd., and NAICO appealed the judgment. In February 2009, we settled with certain of these parties and reduced our liability as of December 31, 2008, by $43 million, including $11 million of interest. On February 17, 2011, the Texas Court of Appeals upheld the dismissals of the tort and punitive damages claims and reversed and remanded the contract claim and attorney fee claims for further proceedings. The appellate court ruling is subject to a potential appeal to the Texas Supreme Court. If the appellate court judgment is upheld, our remaining liability could be less than the amount of our accrual for these matters.

  Royalty litigation

Notes (Continued)

     In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for the proceeds that we received from the sale of natural gas and extracted products, improperly charged certain expenses, and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify as a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments resulting from calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class members for class certification, reserved two claims for court resolution, resolved all other class claims relating to past calculation of royalty and overriding royalty payments, and established certain rules to govern future royalty and overriding royalty payments. This settlement resolved all claims relating to past withholding for ad valorem tax payments and established a procedure for refunds of any such excess withholding in the future. The first reserved claim is whether we are entitled to deduct in our calculation of royalty payments a portion of the costs we incur beyond the tailgates of the treating or processing plants for mainline pipeline transportation. We received a favorable ruling on our motion for summary judgment on the first reserved claim. Plaintiffs appealed that ruling and the Colorado Court of Appeals found in our favor in April 2011. We anticipate knowing later in 2011 whether plaintiffs will pursue any further appeal on the first reserved claim. The second reserved claim relates to whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are thus entitled to deduct a proportionate share of transportation costs in calculating royalty payments. We anticipate trial on the second reserved claim following resolution of the first reserved claim. We believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law. At this time, the plaintiffs have not provided us a sufficient framework to calculate an estimated range of exposure related to their claims. However, it is reasonably possible that the ultimate resolution of this item could result in a future charge that may be material to our results of operations.

     Other producers have been in litigation or discussions with a federal regulatory agency and a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to these matters, we have monitored them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. One of these matters involving federal litigation was decided on October 5, 2009. The resolution of this specific matter is not material to us. However, other related issues in these matters that could be material to us remain outstanding. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (ONRR) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to our federal leases in New Mexico. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for leases in other states, but such guidelines are expected in the future. However, the timing of receipt of the necessary guidelines is uncertain. In addition, these interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and will vary based upon the ONRR’s assessment of the configuration of processing, treating and transportation operations supporting each federal lease. From January 2004 through December 2010, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $55 million. Based on correspondence in 2009 with the ONRR’s predecessor, we believe our calculating assumptions have been consistent with the requirements. The issuance of similar guidelines in Colorado and other states could affect our previous royalty payments and the effect could be material to our results of operations.

  Other

     In 2003, we entered into an agreement to sublease certain underground storage facilities to Liberty Gas Storage (Liberty). We have asserted claims against Liberty for prematurely terminating the sublease and for damage caused to the facilities. In February 2011, Liberty asserted a counterclaim for costs in excess of $200 million associated with its use of the facilities. Due to the lack of information currently available, we are unable to evaluate the merits of the counterclaim and determine the amount of any possible liability.

Notes (Continued)

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, property damage, environmental matters, right of way and other representations that we have provided.

     At March 31, 2011, 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 our results of operations in the period in which the claim is made.

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

Summary

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

Note 12. Segment Disclosures

     Our reporting segments are Williams Partners, Exploration & Production and Midstream Canada & Olefins. All remaining business activities are included in Other. (See Note 2.)

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, equity earnings (losses) and income (loss) from investments. Intersegment sales are generally accounted for at current market prices as if the sales were to unaffiliated third parties.

     The primary types of costs and operating expenses by segment can be generally summarized as follows:

•

Williams Partners—commodity purchases (primarily for NGL and crude marketing, shrink and fuel), depreciation and operation and maintenance expenses;

•

Exploration & Production—commodity purchases (primarily in support of commodity marketing and risk management activities), depletion, depreciation and amortization, lease and facility operating expenses and operating taxes;

•

Midstream Canada & Olefins—commodity purchases (primarily for shrink, feedstock and NGL and olefin marketing activities), depreciation and operation and maintenance expenses.

Notes (Continued)

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

						Exploration				Midstream
		Williams				&				Canada &
		Partners				Production				Olefins				Other				Eliminations				Total
		(Millions)
Three months ended March 31, 2011
Segment revenues:
External		$	1,478			$	779			$	316			$	2			$	—			$	2,575
Internal			101				210				—				4				(315	)			—
Total revenues		$	1,579			$	989			$	316			$	6			$	(315	)		$	2,575
Segment profit (loss)		$	437			$	51			$	74			$	20			$	—			$	582
Less:
Equity earnings (losses)			25				6				—				9				—				40
Income (loss) from investments			—				—				—				11				—				11
Segment operating income (loss)		$	412			$	45			$	74			$	—			$	—				531
General corporate expenses																							(51	)
Total operating income (loss)																						$	480
Three months ended March 31, 2010
Segment revenues:
External		$	1,397			$	925			$	267			$	2			$	—			$	2,591
Internal			93				232				5				4				(334	)			—
Total revenues		$	1,490			$	1,157			$	272			$	6			$	(334	)		$	2,591
Segment profit (loss)		$	424			$	153			$	20			$	7			$	—			$	604
Less equity earnings (losses)			26				5				—				9				—				40
Segment operating income (loss)		$	398			$	148			$	20			$	(2	)		$	—				564
General corporate expenses																							(85	)
Total operating income (loss)																						$	479

     Total segment revenues for Exploration & Production include $405 million and $556 million of gas management revenues for the three months ended March 31, 2011 and 2010, respectively. Gas management revenues include sales of natural gas in conjunction with marketing services provided to third parties and intercompany sales of fuel and shrink gas to the midstream businesses in Williams Partners. These revenues are substantially offset by similar amounts of gas management costs.

Notes (Continued)

     The following table reflects total assets by reporting segment.

		Total Assets
		March 31, 2011				December 31, 2010
		(Millions)
Williams Partners		$	13,437			$	13,404
Exploration & Production			9,735				9,827
Midstream Canada & Olefins			1,014				922
Other			3,588				3,481
Eliminations			(2,691	)			(2,662	)
Total		$	25,083			$	24,972

Item 2

Management’s Discussion and Analysis of
Financial Condition and Results of Operations

Changes in Structure and Dividend Increase

     On February 16, 2011, we announced our reorganization plan to divide our business into two separate, publicly traded corporations. On April 29, 2011, our wholly owned subsidiary, WPX Energy, Inc. (WPX), filed a registration statement with the SEC with respect to an initial public offering of its equity securities. This is the first step in our reorganization plan, which calls for a separation of our exploration and production business through an initial public offering of up to 20 percent of WPX in 2011 and a tax-free spin-off of our remaining interest in WPX to our shareholders in 2012, after which Williams would continue as a premier natural gas infrastructure company. We retain the discretion to determine whether and when to complete these transactions. In conjunction with the initial public offering, we expect WPX to establish a new credit facility and issue senior unsecured notes. We expect that a substantial portion of the combined net proceeds of these transactions will be used to repay a portion of our existing debt.

     Additionally, in April 2011 our Board of Directors approved a regular quarterly dividend payable in June 2011 of $0.20 per share, which reflects an increase of 60 percent compared to the $0.125 per share paid to our shareholders in each of the last four quarters.

     Management believes these actions will serve to enhance the growth potential and overall valuation of our assets.

Overview of Three Months Ended March 31, 2011

     Income (loss) from continuing operations attributable to The Williams Companies, Inc., for the three months ended March 31, 2011, changed favorably by $524 million compared to the three months ended March 31, 2010. This change includes:

	•		The absence of $645 million of pre-tax costs attributable to The Williams Companies, Inc., associated with our 2010 restructuring, including $606 million of early debt retirement costs.
	•		A $124 million tax benefit recorded in first-quarter 2011 associated with federal settlements and an international revised assessment. (See Note 5 of Notes to Consolidated Financial Statements.)
	•		A $54 million improvement in operating income at Midstream Canada & Olefins due to higher olefin and NGL margins primarily from higher per-unit margins. (See Results of Operations — Segments, Midstream Canada & Olefins).
	•		Slightly improved operating income at Williams Partners primarily due to higher fee revenues and improved NGL prices, offset by lower volumes. (See Results of Operations — Segments, Williams Partners).

     Partially offsetting these favorable changes are lower operating results within Exploration & Production. (See Results of Operations — Segments, Exploration & Production.)

See additional discussion in Results of Operations.

     Our net cash provided by operating activities for the three months ended March 31, 2011, increased $194 million compared to the three months ended March 31, 2010, primarily due to net favorable changes in working capital. (See Management’s Discussion and Analysis of Financial Condition and Liquidity.)

Management’s Discussion and Analysis (Continued)

Recent Events

     Beginning with the first quarter of 2011, we changed our segment reporting structure to present our Canadian midstream and domestic olefins operations as a separate segment, Midstream Canada & Olefins. These operations were previously reported within Other. Prior periods have been recast to reflect this revised segment presentation.

     In March 2011, Midstream Canada & Olefins announced a long-term agreement under which it will produce up to 17,000 barrels per day of ethane/ethylene mix for a chemical company in Alberta, Canada. We plan to expand two primary facilities located in Alberta to support the new agreement. (See Results of Operations — Segments, Midstream Canada & Olefins.)

     During April 2011, we agreed to contribute an additional 24.5 percent interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream) to WPZ in exchange for aggregate consideration of $297 million of cash and 632,584 limited partner units, and an increase in the capital account of its general partner units to allow us to maintain our 2 percent general partner interest. WPZ expects to fund the cash consideration for this transaction through its credit facility. Upon completing this transaction, which is expected to close during the second quarter of 2011, the Williams Partners segment will hold a 49 percent interest in Gulfstream, while Other will hold a 1 percent interest.

Company Outlook

     We believe we are well positioned to execute on our 2011 business plan and to capture attractive growth opportunities. Economic and commodity price indicators for 2011 and beyond reflect continued improvement in the economic environment. However, given the potential volatility of these measures, the economy could worsen and/or commodity prices could decline, negatively impacting future operating results and increasing the risk of nonperformance of counterparties or impairments of long-lived assets.

     We are positioned to drive additional organic growth and aggressively pursue value-adding growth opportunities. Our structure is designed to lower capital costs, enhance reliable access to capital markets, and create a greater ability to pursue development projects and acquisitions.

     We continue to operate with a focus on Economic Value Added (EVA^®)¹ and invest in our businesses in a way that meets customer needs and enhances our competitive position by:

	•		Continuing to invest in and grow our gathering and processing, interstate natural gas pipeline systems, and natural gas drilling;
	•		Retaining the flexibility to adjust somewhat our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

     Potential risks and/or obstacles that could impact the execution of our plan include:

	•		Lower than anticipated energy commodity prices and margins;
	•		Lower than expected levels of cash flow from operations;
	•		Availability of capital;
	•		Counterparty credit and performance risk;
	•		Decreased drilling success at Exploration & Production;
	•		Decreased volumes from third parties served by our midstream businesses;

Management’s Discussion and Analysis (Continued)

	•		General economic, financial markets, or industry downturn;
	•		Changes in the political and regulatory environments;
	•		Physical damages to facilities, especially damage to offshore facilities by named windstorms.

     We continue to address these risks through utilization of commodity hedging strategies, disciplined investment strategies, and maintaining at least $1 billion in consolidated liquidity from cash and cash equivalents and unused revolving credit facilities. In addition, we utilize master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements.

General

     Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10-Q and our 2010 Annual Report on Form 10-K.

Critical Accounting Estimate

Impairments of Long-Lived Assets

     We evaluate our long-lived assets for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value. Our computations utilize judgments and assumptions that include the estimated fair value of the asset, undiscounted future cash flows, discounted future cash flows, and the current and future economic environment in which the asset is operated.

     As a result of significant declines in forward natural gas prices during the third quarter of 2010, we assessed Exploration & Production’s natural gas producing properties and acquired unproved reserve costs for impairment using estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of natural gas reserves quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and our estimate of an applicable discount rate commensurate with risk of the underlying cash flow estimates. The assessment performed at September 30, 2010, identified certain properties with a carrying value in excess of their calculated fair values which resulted in an impairment charge.

     In addition to those long-lived assets described above for which impairment charges were recorded, certain others were reviewed for which no impairment was required. These reviews included Exploration & Production’s other domestic producing properties and acquired unproved reserve costs, and utilized inputs generally consistent with those described above. Judgments and assumptions are inherent in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements. For Exploration & Production’s other producing assets reviewed, but for which impairment charges were not recorded, we estimate that approximately 9 percent could be at risk for impairment if forward prices across all future periods decline by approximately 8 percent, on average, as compared to the forward prices at December 31, 2010. A substantial portion of the remaining carrying value of these other assets (primarily related to Exploration & Production’s assets in the Piceance basin) could be at risk for impairment if forward prices across all future periods decline by at least 30 percent, on average, as compared to the prices at December 31, 2010. At March 31, 2011, forward natural gas prices remained above those used in our year-end analysis. As a result, we have not re-evaluated these assets for impairment.

Management’s Discussion and Analysis (Continued)

Results of Operations

Consolidated Overview

     The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2011, compared to the three months ended March 31, 2010. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

		Three months ended
		March 31,
		2011				2010				$ Change*				% Change*
		(Millions)
Revenues		$	2,575			$	2,591				-16				-1	%
Costs and expenses:
Costs and operating expenses			1,908				1,917				+9				0	%
Selling, general and administrative expenses			137				111				-26				-23	%
Other (income) expense — net			(1	)			(1	)			—				0	%
General corporate expenses			51				85				+34				+40	%
Total costs and expenses			2,095				2,112
Operating income (loss)			480				479
Interest accrued — net			(149	)			(147	)			-2				-1	%
Investing income — net			51				39				+12				+31	%
Early debt retirement costs			—				(606	)			+606				+100	%
Other income (expense) — net			4				(7	)			+11			NM
Income (loss) from continuing operations before income taxes			386				(242	)
Provision (benefit) for income taxes			(6	)			(94	)			-88				-94	%
Income (loss) from continuing operations			392				(148	)
Income (loss) from discontinued operations			(8	)			2				-10			NM
Net income (loss)			384				(146	)
Less: Net income attributable to noncontrolling interests			63				47				-16				-34	%
Net income (loss) attributable to The Williams Companies, Inc.		$	321			$	(193	)