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 March 31, 2009

or

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

For the transition period from                      to                     

Commission file number 1-4174

THE WILLIAMS COMPANIES, INC.

 

(Exact name of registrant as specified in its charter)

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

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

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

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

      Indicate by check mark whether the registrant 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). o 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):

     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 April 27, 2009
Common Stock, $1 par value		580,096,386 Shares

 

 

The Williams Companies, Inc.
Index

		Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Operations — Three Months Ended March 31, 2009 and 2008			3
Consolidated Balance Sheet — March 31, 2009 and December 31, 2008			4
Consolidated Statement of Changes in Equity — Three Months Ended March 31, 2009 and 2008			5
Consolidated Statement of Cash Flows — Three Months Ended March 31, 2009 and 2008			6
Notes to Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
Item 3. Quantitative and Qualitative Disclosures about Market Risk			48
Item 4. Controls and Procedures			50
Part II. Other Information			50
Item 1. Legal Proceedings			50
Item 1A. Risk Factors			50
Item 6. Exhibits			52
EX-12
EX-31.1
EX-31.2
EX-32

     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 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,” “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;
	•		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 and natural gas liquids (NGL) 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 which could cause actual results to differ from those in the forward-looking statements include:

	•		Availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future natural gas 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 the current economic slowdown and the disruption of 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 proposed climate change legislation), 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;
	•		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;
	•		Our exposure to the credit risk of our customers;
	•		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, 2008, and Part II, Item 1A. Risk Factors of this Form 10-Q.

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

		Three months
		ended March 31,
(Dollars in millions, except per-share amounts)		2009				2008
Revenues:
Exploration & Production		$	553			$	728
Gas Pipeline			401				413
Midstream Gas & Liquids			899				1,557
Gas Marketing Services			867				1,650
Other			7				6
Intercompany eliminations			(599	)			(1,150	)
Total revenues			2,128				3,204
Segment costs and expenses:
Costs and operating expenses			1,668				2,353
Selling, general and administrative expenses			123				112
Provision for doubtful accounts and notes			50				(1	)
Other (income) expense — net			270				(117	)
Total segment costs and expenses			2,111				2,347
General corporate expenses			40				42
Operating income (loss):
Exploration & Production			74				427
Gas Pipeline			164				170
Midstream Gas & Liquids			(220	)			238
Gas Marketing Services			(2	)			21
Other			1				1
General corporate expenses			(40	)			(42	)
Total operating income (loss)			(23	)			815
Interest accrued			(166	)			(165	)
Interest capitalized			20				8
Investing income (loss)			(61	)			55
Other income (expense) — net			(2	)			5
Income (loss) from continuing operations before income taxes			(232	)			718
Provision (benefit) for income taxes			(15	)			263
Income (loss) from continuing operations			(217	)			455
Income (loss) from discontinued operations			(7	)			84
Net income (loss)			(224	)			539
Less: Net income (loss) attributable to noncontrolling interests			(52	)			39
Net income (loss) attributable to The Williams Companies, Inc.		$	(172	)		$	500
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations		$	(165	)		$	416
Income (loss) from discontinued operations			(7	)			84
Net income (loss)		$	(172	)		$	500
Basic earnings (loss) per common share:
Income (loss) from continuing operations		$	(.29	)		$	.71
Income (loss) from discontinued operations			(.01	)			.14
Net income (loss)		$	(.30	)		$	.85
Weighted-average shares (thousands)			579,495				585,518
Diluted earnings (loss) per common share:
Income (loss) from continuing operations		$	(.29	)		$	.70
Income (loss) from discontinued operations			(.01	)			.14
Net income (loss)		$	(.30	)		$	.84
Weighted-average shares (thousands)			579,495				598,627
Cash dividends declared per common share		$	.11			$	.10

See accompanying notes.

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

		March 31,				December 31,
(Dollars in millions, except per-share amounts)		2009				2008
ASSETS
Current assets:
Cash and cash equivalents		$	1,786			$	1,439
Accounts and notes receivable (net of allowance of $90 at March 31, 2009 and $40 at December 31, 2008)			683				941
Inventories			242				260
Derivative assets			1,077				1,464
Other current assets and deferred charges			271				307
Total current assets			4,059				4,411
Investments			902				971
Property, plant and equipment, at cost			25,926				25,936
Less accumulated depreciation, depletion and amortization			(7,932	)			(7,871	)
Property, plant and equipment — net			17,994				18,065
Derivative assets			877				986
Goodwill			1,011				1,011
Other assets and deferred charges			525				562
Total assets		$	25,368			$	26,006
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	828			$	1,059
Accrued liabilities			1,058				1,171
Derivative liabilities			567				1,093
Long-term debt due within one year			164				196
Total current liabilities			2,617				3,519
Long-term debt			8,278				7,683
Deferred income taxes			3,374				3,390
Derivative liabilities			746				875
Other liabilities and deferred income			1,497				1,485
Contingent liabilities and commitments (Note 14)
Equity:
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 615 million issued at March 31, 2009 and 613 million shares issued at December 31, 2008)			615				613
Capital in excess of par value			8,076				8,074
Retained earnings			639				874
Accumulated other comprehensive income (loss)			37				(80	)
Less treasury stock, at cost (35 million shares of common stock)			(1,041	)			(1,041	)
Total stockholders’ equity			8,326				8,440
Noncontrolling interests in consolidated subsidiaries			530				614
Total equity			8,856				9,054
Total liabilities and equity		$	25,368			$	26,006

See accompanying notes.

The Williams Companies, Inc.
Consolidated Statement of Changes in Equity
(Unaudited)

		Three months ended March 31,
		2009												2008
		The Williams				Noncontrolling								The Williams				Noncontrolling
(Dollars in millions)		Companies, Inc.				Interests				Total				Companies, Inc.				Interests				Total
Beginning balance		$	8,440			$	614			$	9,054			$	6,375			$	1,430			$	7,805
Comprehensive income:
Net income (loss)			(172	)			(52	)			(224	)			500				39				539
Other comprehensive income (loss), net of tax:
Net unrealized gain (loss) on cash flow hedges, net of reclassification adjustments			123				—				123				(122	)			2				(120	)
Foreign currency translation adjustments			(13	)			—				(13	)			(21	)			—				(21	)
Pension benefits — amortization of net actuarial loss			7				—				7				2				—				2
Total other comprehensive income (loss)			117				—				117				(141	)			2				(139	)
Total comprehensive income (loss)			(55	)			(52	)			(107	)			359				41				400
Cash dividends — common stock			(64	)			—				(64	)			(59	)			—				(59	)
Dividends and distributions to noncontrolling interests			—				(33	)			(33	)			—				(24	)			(24	)
Sale of limited partner units of consolidated partnerships			—				—				—				—				362				362
Conversion of Williams Partners L.P. subordinated units to common units			—				—				—				1,225				(1,225	)			—
Purchase of treasury stock			—				—				—				(126	)			—				(126	)
Stock-based compensation, net of tax			5				—				5				19				—				19
Other			—				1				1				8				(1	)			7
Ending balance		$	8,326			$	530			$	8,856			$	7,801			$	583			$	8,384

See accompanying notes.

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

		Three months ended March 31,
(Dollars in millions)		2009				2008
OPERATING ACTIVITIES:
Net income (loss)		$	(224	)		$	539
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization			367				302
Provision (benefit) for deferred income taxes			(38	)			153
Provision for loss on investments, property and other assets			339				2
Gain on sale of contractual production rights			—				(118	)
Provision for doubtful accounts and notes			50				(1	)
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable			245				(62	)
Inventories			13				(80	)
Margin deposits and customer margin deposits payable			(2	)			38
Other current assets and deferred charges			(13	)			8
Accounts payable			(60	)			98
Accrued liabilities			(216	)			(117	)
Changes in current and noncurrent derivative assets and liabilities			37				(19	)
Other, including changes in noncurrent assets and liabilities			14				50
Net cash provided by operating activities			512				793
FINANCING ACTIVITIES:
Proceeds from long-term debt			595				100
Payments of long-term debt			(31	)			(115	)
Proceeds from sale of limited partner units of consolidated partnerships			—				362
Dividends paid			(64	)			(59	)
Purchase of treasury stock			—				(93	)
Dividends and distributions paid to noncontrolling interests			(33	)			(24	)
Changes in restricted cash			36				7
Changes in cash overdrafts			(41	)			(31	)
Other — net			(6	)			15
Net cash provided by financing activities			456				162
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures			(484	)			(579	)
Changes in accounts payable and accrued liabilities			(128	)			43
Proceeds from sale of contractual production rights			—				118
Other — net			(9	)			4
Net cash used by investing activities			(621	)			(414	)
Increase in cash and cash equivalents			347				541
Cash and cash equivalents at beginning of period			1,439				1,699
Cash and cash equivalents at end of period		$	1,786			$	2,240

See accompanying notes.

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

Note 1. General

     Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto in our Annual Report on Form 10-K. The accompanying unaudited financial statements include all normal recurring adjustments that, in the opinion of our management, are necessary to present fairly our financial position at March 31, 2009, and results of operations and cash flows for the three months ended March 31, 2009 and 2008.

     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.

Goodwill

     We perform interim assessments of goodwill if indicators of potential impairment exist. We consider a decrease in our total market capitalization below our consolidated stockholders’ equity to be an indicator of potential goodwill impairment. As of March 31, 2009, our total market capitalization was below our consolidated stockholders’ equity. We performed an interim evaluation as of March 31, 2009, and determined that no impairment of our goodwill was necessary. It is reasonably possible that we may be required to conduct an interim goodwill impairment evaluation again during 2009, which could result in a material impairment of goodwill.

Note 2. Basis of Presentation

     Prior period amounts reported for Exploration & Production have been adjusted to reflect the presentation of certain revenues and costs on a net basis. These adjustments reduced revenues and reduced costs and operating expenses by the same amount, with no net impact on segment profit. The reductions for first quarter of 2008 were $20 million.

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

Noncontrolling Interests in Consolidated Subsidiaries

     In January 2009, we adopted Statement of Financial Accounting Standards (SFAS) No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of Accounting Research Bulletin No. 51.” SFAS No. 160 establishes accounting and reporting standards for noncontrolling ownership interests in subsidiaries (previously referred to as minority interests) and is applied prospectively with the exception of the presentation and disclosure requirements which must be applied retrospectively for all periods presented. Noncontrolling ownership interests in consolidated subsidiaries are now presented in the consolidated balance sheet within equity as a component separate from stockholders’ equity. Net income (loss) now includes earnings (loss) attributable to both The Williams Companies, Inc., and the noncontrolling interests. Earnings per share continues to be based on earnings attributable to only The Williams Companies, Inc.

Master Limited Partnerships

     We currently own approximately 23.6 percent of Williams Partners L.P., including the interests of the general partner, which is wholly owned by us, and incentive distribution rights. 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

Notes (Continued)

(Midstream) segment. For 2009 distribution periods, we have agreed to waive our general partner incentive distribution rights, which we estimate would total $29 million based on current distribution levels. We have also agreed to provide a credit of up to $10 million to Williams Partners L.P. if general and administrative expenses exceed specified levels. This will decrease our total allocation of income from Williams Partners L.P., resulting in decreased net income attributable to The Williams Companies, Inc. and increased net income attributable to noncontrolling interests.

     We hold approximately 47.7 percent of the interests in Williams Pipeline Partners L.P., including the interests of the general partner, which is wholly owned by us, and incentive distribution rights. In accordance with EITF Issue No. 04-5, we consolidate Williams Pipeline Partners L.P. within our Gas Pipeline segment due to our control through the general partner.

Note 3. Venezuela Operations and Investments

     Our Venezuela operations are primarily within our Midstream segment and are operated under long-term agreements for the exclusive benefit of the Venezuelan state-owned oil company, Petróleos de Venezuela S.A. (PDVSA). These operations include majority ownership in entities that own and operate gas compression facilities, as well as our equity investment in Accroven, which owns gas processing facilities and an NGL fractionation plant. Construction of these assets was funded through project financing that is collateralized by the stock, assets, and contract rights of the entities and is nonrecourse to us.

     The collection of receivables from PDVSA has historically been slower and required more effort than other customers due to its policies and the political environment in Venezuela. As noted in our Annual Report on Form 10-K for the year ended December 31, 2008, PDVSA had failed to make regular payments to many service providers, including us. The past due payments from PDVSA triggered technical default of the related project debt in the fourth quarter of 2008, which resulted in classification of the entire debt balance as current. As of March 31, 2009, long-term debt due within one year includes $161 million of this debt, of which $38 million has a stated maturity within one year.

     We previously expected PDVSA to resume regular payments following a February 15, 2009, referendum vote in Venezuela; however, that has not happened. PDVSA’s continued nonperformance with us and others in the industry, their financial distress, and lack of communications with us has caused us to revise our assessment. We now believe it is probable that PDVSA will not cure the defaults. Without substantial payments from PDVSA, these operations will be forced to shut down. As required under our agreements, we have provided PDVSA with default notices for our majority-owned operations and expect Accroven to send similar notice in May 2009. In the event that PDVSA does not cure the defaults and does not comply with its contractual obligations to purchase the related assets, we will pursue all rights available to us under our agreements, including international arbitration.

     As previously noted, the debt supporting these operations is fully secured by the assets, contract rights, and the stock of the project entities. The default under the loan agreements allows the lenders to, among other things, terminate their commitment to lend, accelerate the payments due, protect their rights and remedies by appropriate proceedings, or seek to enforce the agreements. To date, the lenders have elected to either defer or not pursue their available rights.

     As a result of these circumstances and developments and our assessment of the low likelihood of PDVSA curing the defaults, we have fully reserved accounts receivable from PDVSA. In addition, we have ceased revenue recognition of these operations for the first quarter of 2009 as we no longer believe that the collectibility of revenues is reasonably assured. This indicator of impairment caused us to review our Venezuelan property, plant and equipment for recoverability and record an impairment charge based on the excess of the carrying value of the assets over their estimated fair value. We estimated fair value using probability-weighted discounted cash flow estimates that considered expected cash flows from (1) the continued operation of the assets considering a complete cure of the default or a partial payment and renegotiation of the contracts, (2) the purchase of the assets by PDVSA and (3) the results of arbitration with varying degrees of award and collection. Considering the risk associated with operating in Venezuela, we utilized an after-tax discount rate of 20 percent. The use of alternate judgments and/or assumptions would have resulted in the recognition of a different impairment charge. We applied similar estimates and assumptions in evaluating our investment in Accroven and recognized an other-than-temporary loss in value. Certain deferred charges and credits have also been written off because the related future cash inflows and outflows are no longer expected to occur.

Notes (Continued)

     In addition, Exploration & Production has a four percent interest in a Venezuelan corporation which owns and operates oil and gas activities. This investment resulted from our previous 10 percent direct working interest in a concession that was converted to a reduced interest in a mixed company at the direction of the Venezuelan government in 2006. Considering our evaluation of the deteriorating financial condition of this corporation, we have recorded an other-than-temporary decline in value for our remaining investment balance.

     All of these charges, along with the corresponding tax impact, are summarized as follows:

		Three months ended
Impact of Impairments and Related Charges on Consolidated Statement of Operations		March 31, 2009
		(Millions)
Fully reserve accounts receivable		$	48	(a)
Impairment of property, plant and equipment			211	(b)
Write-off of deferred charges and credits			30	(b)
Other			6	(b)
			295
Impairment of equity investment in Accroven			75	(c)
Impairment of Exploration & Production’s cost-based investment			11	(d)
Income tax benefit from reversal of deferred tax balances			(76	) (e)
Net loss		$	305
Net loss attributable to noncontrolling interests		$	64
Net loss attributable to The Williams Companies, Inc.		$	241
Classification within Consolidated Statement of Operations:

	(a)		Provision for doubtful accounts and notes
	(b)		Other (income) expense — net within segment costs and expenses
	(c)		Loss from investments within Investing income (loss)
	(d)		Investing income (loss)
	(e)		Provision (benefit) for income taxes

     Included within Other above is a $2 million loss related to an interest rate cap that was previously designated as a cash flow hedge. We concluded that related future interest payments were probable of not occurring and, thus, discontinued cash flow hedge accounting and reclassified this amount from accumulated other comprehensive income into earnings.

     In addition to the above charges, Midstream’s Venezuela operations incurred an additional first-quarter 2009 net loss of $10 million, of which $5 million is attributable to noncontrolling interests.

     After these adjustments, our carrying value as of March 31, 2009, associated with these operations is primarily comprised of $67 million of restricted cash, $106 million of property, plant and equipment, and $161 million of secured debt.

Note 4. Discontinued Operations

     Results of discontinued operations are summarized as follows:

		Three months ended
		March 31,
		2009				2008
		(Millions)
Revenues		$	—			$	—
Income (loss) from discontinued operations before income taxes		$	(7	)		$	132
Provision for income taxes			—				(48	)
Income (loss) from discontinued operations		$	(7	)		$	84

     In first-quarter 2008, we recognized pre-tax income of $128 million in income (loss) from discontinued operations before income taxes related to our former Alaska operations. This amount includes $74 million related to cash received upon the favorable resolution of a matter involving pipeline transportation rates and $54 million related to a reduction of remaining amounts accrued in excess of our obligation associated with the Trans-Alaska Pipeline System Quality Bank.

Notes (Continued)

Note 5. Asset Sales, Impairments and Other Accruals

     The following table presents significant gains or losses from asset sales, impairments and other accruals or adjustments reflected in other (income) expense — net within segment costs and expenses.

		Three months ended
		March 31,
		2009				2008
		(Millions)
Exploration & Production
Gain on sale of contractual right to an international production payment		$	—			$	(118	)
Penalties from early release of drilling rigs			34				—
Impairments of certain gathering assets (see Note 12)			5				—
Midstream
Impairments and related charges associated with Venezuela operations (see Note 3)			247				—

Note 6. Provision (Benefit) for Income Taxes

     The provision (benefit) for income taxes includes:

		Three months ended
		March 31,
		2009				2008
		(Millions)
Current:
Federal		$	12			$	108
State			2				17
Foreign			9				14
			23				139
Deferred:
Federal			34				102
State			4				16
Foreign			(76	)			6
			(38	)			124
Total provision (benefit)		$	(15	)		$	263

     The effective income tax rate on the total benefit for the three months ended March 31, 2009 is less than the federal statutory rate due primarily to the valuation allowance on foreign taxes related to the Venezuelan impairments and write-offs partially offset by the impact of nontaxable noncontrolling interests. (See Note 3.)

     The effective income tax rate on the total provision for the three months ended March 31, 2008 is greater than the federal statutory rate due primarily to the effect of state income taxes partially offset by the impact of nontaxable noncontrolling interests.

     During the next twelve months, we do not expect ultimate resolution of any unrecognized tax benefit associated with a domestic or international matter will have a material impact on our financial position. However, certain matters we have contested to the Internal Revenue Service Appeals Division could be resolved and result in a reduction to our unrecognized tax benefit.

Notes (Continued)

Note 7. Earnings (Loss) Per Common Share from Continuing Operations

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

		Three months ended March 31,
		2009				2008
		(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)		$	(165	)		$	416
Basic weighted-average shares (2)			579,495				585,518
Effect of dilutive securities:
Nonvested restricted stock units			—				1,465
Stock options			—				4,325
Convertible debentures			—				7,319
Diluted weighted-average shares			579,495				598,627
Earnings (loss) per common share from continuing operations:
Basic		$	(.29	)		$	.71
Diluted		$	(.29	)		$	.70

     For the three months ended March 31, 2009, 1.4 million weighted-average nonvested restricted stock units and 1.5 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 the loss from continuing operations attributable to The Williams Companies, Inc.

     Additionally, for the three months ended March 31, 2009, 4.8 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, 2009, 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,				March 31,
		2009				2008
Options excluded (millions)			6.7				2.2
Weighted-average exercise prices of options excluded			$25.62				$37.10
Exercise price ranges of options excluded		$	15.71 - $42.29			$	34.54 - $42.29
First quarter weighted-average market price			$13.05				$33.97

Notes (Continued)

Note 8. Employee Benefit Plans

     Net periodic benefit expense is as follows:

										Other Postretirement
		Pension Benefits								Benefits
		Three months								Three months
		ended March 31,								ended March 31,
		2009				2008				2009				2008
						(Millions)
Components of net periodic benefit expense:
Service cost		$	7			$	5			$	—			$	1
Interest cost			15				14				4				4
Expected return on plan assets			(14	)			(20	)			(2	)			(3	)
Amortization of prior service credit			—				—				(2	)			—
Amortization of net actuarial loss			11				2				1				—
Amortization of regulatory asset			—				—				1				1
Net periodic benefit expense		$	19			$	1			$	2			$	3

     During the three months ended March 31, 2009, we contributed $16 million to our pension plans and $4 million to our other postretirement benefit plans. During April 2009, we contributed an additional $45 million to our pension plans for a total of $61 million. We do not presently anticipate making any additional contributions to our pension plans in the remainder of 2009. We presently anticipate making additional contributions of approximately $12 million to our other postretirement benefit plans in 2009 for a total of approximately $16 million.

Note 9. Inventories

     Inventories are as follows:

		March 31,				December 31,
		2009				2008
		(Millions)
Natural gas liquids		$	45			$	56
Natural gas in underground storage			82				97
Materials, supplies and other			115				107
		$	242			$	260

Note 10. Debt and Banking Arrangements

Revolving Credit and Letter of Credit Facilities (Credit Facilities)

     At March 31, 2009, no loans are outstanding under our credit facilities. Letters of credit issued under our credit facilities are:

		Credit Facilities				Letters of Credit at
		Expiration				March 31, 2009
						(Millions)
$400 million unsecured credit facility		April 2009				$	—
$100 million unsecured credit facility		May 2009					—
$700 million unsecured credit facilities		September 2010					236
$1.5 billion unsecured credit facility		May 2012					75
$200 million Williams Partners L.P. unsecured credit facility		December 2012					—
						$	311

     Lehman Commercial Paper Inc., which is committed to fund up to $70 million of our $1.5 billion revolving credit facility, filed for bankruptcy in October 2008. Lehman Brothers Commercial Bank, which has not filed for bankruptcy, is committed to fund up to $12 million of Williams Partners L.P.’s $200 million revolving credit facility. We expect that our ability to borrow under these facilities is reduced by these committed amounts. The committed amounts of other participating banks under these agreements remain in effect and are not impacted by the above.

Notes (Continued)

Issuances and Retirements

     On March 5, 2009, we issued $600 million aggregate principal amount of 8.75 percent senior unsecured notes due 2020 to certain institutional investors in a private debt placement. In connection with this issuance, we are obligated to file a registration statement offering to exchange the notes for a new issue of substantially identical notes (except they will not be subject to transfer restrictions) to be registered under the Securities Act of 1933, as amended, within 180 days after the March 5, 2009 closing. We are obligated to use commercially reasonable efforts to cause such registration statements to be declared effective within 270 days after closing. We may also be required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If we fail to fulfill these obligations, we may be required to pay additional interest on the affected securities. The rate of additional interest will be 0.25 percent per annum on the principal amount of the affected securities for the first 90-day period immediately following the default, increasing over time up to a maximum amount of 0.5 percent annually.

Note 11. 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. For the three months ended March 31, 2009, we have not incurred any significant losses due to counterparty bankruptcy filings.

     The gross credit exposure from our derivative contracts as of March 31, 2009, is summarized as follows.

		Investment
Counterparty Type		Grade(a)				Total
		(Millions)
Gas and electric utilities		$	37			$	38
Energy marketers and traders			81				658
Financial institutions			1,268				1,269
		$	1,386				1,965
Credit reserves							(11	)
Gross credit exposure from derivatives						$	1,954

     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, 2009, excluding collateral support discussed below, is summarized as follows.

		Investment
Counterparty Type		Grade(a)				Total
		(Millions)
Gas and electric utilities		$	—			$	1
Energy marketers and traders			70				75
Financial institutions			767				767
		$	837				843
Credit reserves							(11	)
Net credit exposure from derivatives						$	832

Notes (Continued)

     Our nine largest net counterparty positions represent approximately 99 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Included within this group are six counterparty positions, representing 81 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, 2009, the designated collateral agent held $378 million of collateral support on our behalf under Exploration & Production’s hedging facility. In addition, we held collateral support, including letters of credit, of $36 million related to our other derivative positions.

Note 12. Fair Value Measurements

     Fair value is the amount received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market based measurement considered from the perspective of a market participant. We use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

     The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:

	•		Level 1 — Quoted prices for identical assets in active markets or liabilities that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 primarily consists of financial instruments that are exchange traded, including certain instruments that were part of sales transactions in 2007 and remain to be assigned to the purchaser. These unassigned instruments are entirely offset by reciprocal positions entered into directly with the purchaser. These reciprocal positions have also been included in Level 1.
	•		Level 2 — Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 primarily consists of over-the-counter (OTC) instruments such as forwards and swaps.
	•		Level 3 — Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 consists of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value. Instruments in this category primarily include OTC options.

     In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.

Notes (Continued)

     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.

Fair Value Measurements Using:

		March 31, 2009																December 31, 2008
		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
		(Millions)																(Millions)
Assets:
Energy derivatives		$	322			$	945			$	687			$	1,954			$	680			$	1,223			$	547			$	2,450
Other assets			11				—				7				18				13				—				7				20
Total assets		$	333			$	945			$	694			$	1,972			$	693			$	1,223			$	554			$	2,470
Liabilities:
Energy derivatives		$	296			$	969			$	48			$	1,313			$	615			$	1,313			$	40			$	1,968
Total liabilities		$	296			$	969			$	48			$	1,313			$	615			$	1,313			$	40			$	1,968

     Energy derivatives include commodity based exchange-traded contracts and OTC contracts. Exchange-traded contracts include futures and options. OTC contracts include forwards, swaps and options.

     Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.

     The determination of fair value also incorporates the time value of money and credit risk factors including the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash deposits and letters of credit) and our nonperformance risk on our liabilities.

     Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.

     Contracts for which fair value can be estimated from executed transactions or broker quotes corroborated by other market data are generally classified within Level 2. 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. Our 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 expiring in the next 36 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 by management.

     Certain instruments trade in less active markets with lower availability of pricing information requiring valuation models using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The fair value of options is estimated using an industry standard Black-Scholes option pricing model. Certain inputs into the model are generally observable, such as commodity prices and interest rates, whereas other model inputs, such as implied volatility by location, are unobservable and require judgment in estimating. The instruments included in Level 3 at March 31, 2009, predominantly consist of options that primarily hedge future sales of production from our Exploration & Production segment, are structured as costless collars, which combine an option to purchase and an option to sell in order to set a minimum and maximum transaction price, and are financially settled.

Notes (Continued)

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

Level 3 Fair Value Measurements Using Significant Unobservable Inputs

		Three months ended March 31,
		2009								2008
		Net Derivatives				Other Assets				Net Derivatives				Other Assets
						(Millions)
Beginning balance		$	507			$	7			$	(14	)		$	10
Realized and unrealized gains (losses):
Included in income (loss) from continuing operations			137				—				6				—
Included in other comprehensive income (loss)			133				—				(179	)			—
Purchases, issuances, and settlements			(138	)			—				2				—
Transfers into Level 3			—				—				(1	)			—
Transfers out of Level 3			—				—				—				—
Ending balance		$	639			$	7			$	(186	)		$	10
Unrealized gains (losses) included in income (loss) from continuing operations relating to instruments still held at March 31		$	—			$	—			$	1			$	—

     Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above period are reported in revenues in our Consolidated Statement of Operations. Reclassification of fair value into and out of Level 3 is made at the end of each quarter.

     The following table presents, by level within the fair value hierarchy, certain assets that have been measured at fair value on a nonrecurring basis.

Fair Value Measurements Using:

		March 31, 2009
																		Total
		Level 1				Level 2				Level 3				Total				Losses for three months ended March 31, 2008
		(Millions)
Impairments:
Midstream Venezuelan property (see Note 3)		$	—			$	—			$	106			$	106			$	(211	)
Midstream investment in Accroven (see Note 3)			—				—				—				—				(75	)
Exploration & Production gathering assets			—				—				11				11				(5	)
Exploration & Production cost-based investment (see Note 3)			—				—				—				—				(11	)
		$	—			$	—			$	117			$	117			$	(302	)

     Exploration & Production recorded an impairment charge of $5 million related to certain gathering assets. This impairment analysis was based on a comparison of the estimated fair value to the carrying value, including an assessment of undiscounted and discounted future cash flows.

Note 13. 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 forecasted sales of NGLs attributable to commodity price risk. Certain of these derivatives utilized for risk management purposes have been designated as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” while other derivatives have not been designated as hedges or do not qualify for hedge accounting despite hedging our future cash flows on an economic basis.

     Exploration & Production produces, buys and sells natural gas at different locations throughout the United States. To reduce exposure to a decrease in revenues 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. Exploration & Production’s cash flow hedges are expected to be highly

Notes (Continued)

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 such that the hedging relationship is considered perfectly effective and no ineffectiveness is recognized in earnings.

     Midstream produces and sells NGLs at different locations throughout the United States. Midstream also buys natural gas to satisfy the required fuel and shrink needed to generate NGLs. 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 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. Midstream’s 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. Midstream does not have any commodity-related cash flow hedges at March 31, 2009.

     Gas Marketing Services supports our natural gas business by providing marketing and risk management services, which include marketing the gas produced by Exploration & Production and procuring fuel and shrink for Midstream. Gas Marketing Services also enters 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 margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk associated with these contracts. Hedges for transportation contracts are designated as cash flow hedges and 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. Hedges for storage contracts have not been designated as SFAS No. 133 hedges, despite economically hedging the expected cash flows generated by those agreements.

Other Activities

     Gas Marketing Services also enters into 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: fixed price, basis, index, and options. The fixed price category includes physical and financial derivative transactions that settle at a fixed location price. The basis category includes financial derivative transactions priced off the difference in value between a commodity at two specific delivery points. The index category includes physical derivative transactions at an unknown future price. The options category includes all fixed price options or combination of options (collars) that set a floor and/or ceiling for the transaction price of a commodity.

Notes (Continued)

     The following table depicts the notional amounts in millions of British Thermal Units of the net long (short) positions in our commodity derivatives portfolio as of March 31, 2009. The volumes presented for options that comprise zero-cost collars represent one side of the short position. While the index volumes are significant, they represent less than 1 percent of the fair value of our net derivative balance.

Derivative Notional Volumes (MMBtu)						Fixed Price				Basis				Index				Options
Designated
Exploration & Production		Risk Management					(54,700,000	)			(49,850,000	)							(264,325,000	)
Gas Marketing Services		Risk Management					—	*			—	*
Not Designated
Exploration & Production		Risk Management													(41,298,800	)
Gas Marketing Services		Risk Management					(7,767,499	)			(7,900,000	)			600,000
Midstream		Risk Management													93,045,413
Gas Marketing Services		Other					(351,286	)			591,000

 

* Volumes related to offsetting positions net to zero.

     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 and 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 twelve 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, 2009
		Assets				Liabilities
		(Millions)
Designated as hedging instruments		$	902			$	129
Not designated as hedging instruments:
Legacy natural gas contracts from former power business			725				756
All other			327				428
Total derivatives not designated as hedging instruments			1,052				1,184
Total derivatives		$	1,954			$	1,313

     The following table presents gains and losses for our energy commodity derivatives designated as cash flow hedges.

		Three months ended
		March 31, 2009				Classification
		(Millions)
Net gain recognized in other comprehensive income (effective portion)		$	325
Net loss reclassified from accumulated other comprehensive income into income (effective portion)		$	(129	)		Revenues
Gain recognized in income (ineffective portion)		$	1			Revenues

     There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness.

     Net gains from energy commodity derivatives not designated as hedging instruments were $11 million for the quarter ended March 31, 2009, and included $15 million in revenues partially offset by $4 million in costs and operating expenses.

     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.

Notes (Continued)

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.

     As of March 31, 2009, we have collateral posted to derivative counterparties totaling $110 million, all of which is in the form of letters of credit, to support the aggregate fair value of our net derivative liability position of $191 million, which includes a reduction of $15 million to our liability balance for our 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 were triggered, was $96 million.

Cash Flow Hedges

     Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in other comprehensive income and are 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, 2009, we have hedged portions of future cash flows associated with anticipated energy commodity purchases and sales for up to four years. Based on recorded values at March 31, 2009, $311 million of net gains (net of income tax provision of $189 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, 2009. 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.

Note 14. 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 U.S. 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.

     As a result of a June 2008 U.S. Supreme Court decision, certain contracts that we entered into during 2000 and 2001 may be subject to partial refunds depending on the results of further proceedings at the FERC. These contracts, under which we sold electricity, totaled approximately $89 million in revenue. While we are not a party to the cases involved in the U.S. Supreme Court decision, the buyer of electricity from us is a party to the cases and claims that we must refund to the buyer any loss it suffers due to the FERC’s reconsideration of the contract terms at issue in the decision. The FERC has directed the parties to provide additional information on certain issues remanded by the U.S. Supreme Court, but delayed the submission of this information to permit the parties to explore possible settlements of the contractual disputes.

Notes (Continued)

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

Refund proceedings

     Although we entered into the State Settlement and Utilities Settlement, which resolved the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, such as the counterparty to the contracts described above and 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 including interest on refund amounts that we might owe to settling and 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 $24 million at March 31, 2009. Collection of the interest and the payment of interest on refund amounts from the escrow accounts is subject to the conclusion of this proceeding. Therefore, we continue to participate in the FERC refund case and related proceedings.

     Challenges to virtually every aspect of the refund proceedings, including the refund period, continue to be made. Because of our settlements, we do not expect that the final resolution of refund obligations will have a material impact on us. Despite two FERC decisions that will affect the refund calculation, significant aspects of the refund calculation process remain unsettled, and the final refund calculation has not been made.

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:

	•		State court litigation in California brought on behalf of certain business and governmental entities that purchased gas for their use. On March 23, 2009, we reached a settlement in principle that will resolve all California litigation.
	•		Class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri, Tennessee and Wisconsin brought on behalf of direct and indirect purchasers of gas in those states.

	•		The federal court in Nevada currently presides over cases that were transferred to it from state courts in Colorado, Kansas, Missouri, and Wisconsin. In 2008, the federal court in Nevada granted summary judgment in the Colorado case in favor of us and most of the other defendants, and on January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal. We expect that the Colorado plaintiffs will appeal.
	•		On October 29, 2008, the Tennessee appellate court reversed the state court’s dismissal of the plaintiffs’ claims on federal preemption grounds and sent the case back to the lower court for further proceedings. We and other defendants appealed the reversal to the Tennessee Supreme Court.
	•		On January 13, 2009, the Missouri state court dismissed a case for lack of standing. The plaintiff has appealed.

Environmental Matters

Continuing operations

     Since 1989, our Transcontinental Gas Pipe Line Company, LLC (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 parties 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 March 31, 2009, we had accrued liabilities of $5 million related to PCB contamination, potential mercury contamination, and other toxic and hazardous substances. Transco has been identified as a potentially responsible party at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, we have estimated our aggregate exposure for remediation of these sites to be less than

Notes (Continued)

$500,000, which is included in the environmental accrual discussed above. We expect that these costs will be recoverable through Transco’s rates.

     Beginning in the mid-1980s, our Northwest Pipeline GP (Northwest Pipeline) subsidiary evaluated many of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. Consistent with other natural gas transmission companies, Northwest Pipeline identified PCB contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, Northwest Pipeline identified hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the EPA in the late 1980s and Northwest Pipeline conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required Northwest Pipeline to reevaluate its previous mercury clean-ups in Washington. Consequently, Northwest Pipeline is conducting additional remediation activities at certain sites to comply with Washington’s current environmental standards. At March 31, 2009, we have accrued liabilities of $9 million for these costs. We expect that these costs will be recoverable through Northwest Pipeline’s rates.

     In March 2008, the EPA issued a new air quality standard for ground level ozone. The new standard will likely impact the operations of our interstate gas pipelines and cause us to incur additional capital expenditures to comply. At this time we are unable to estimate the cost of these additions that may be required to meet the new regulations. We expect that costs associated with these compliance efforts 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, 2009, we have accrued liabilities totaling $6 million for these costs.

     In April 2007, the New Mexico Environment Department’s (NMED) Air Quality Bureau issued a notice of violation (NOV) to Williams Four Corners, LLC (Four Corners) that alleged various emission and reporting violations in connection with our Lybrook gas processing plant’s flare and leak detection and repair program. In December 2007, the NMED proposed a penalty of approximately $3 million. In July 2008, the NMED issued an NOV to Four Corners that alleged air emissions permit exceedances for three glycol dehydrators at one of our compressor facilities and proposed a penalty of approximately $103,000. We are discussing the proposed penalties with the NMED.

     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. We met with the EPA and are exchanging information in order to resolve the issues.

     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 NOVs alleging violations of Clean Air Act requirements at these compressor stations. We met with the EPA in May 2008 and submitted our response denying the allegations in June 2008.

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 March 31, 2009, we have accrued liabilities of $9 million for such excess costs.

Notes (Continued)

     Other

     At March 31, 2009, we have accrued environmental liabilities of $13 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.

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

Summary of environmental matters

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

Other Legal Matters

Will Price (formerly Quinque)

     In 2001, fourteen of our entities were named as defendants in a nationwide class action lawsuit in Kansas state court that had been pending against other defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and sought an unspecified amount of damages. The fourth amended petition, which was filed in 2003, deleted all of our defendant entities except two Midstream subsidiaries. All remaining defendants have opposed class certification and a hearing on plaintiffs’ second motion to certify the class was held in April 2005. We are awaiting a decision from the court. The amount of any possible liability cannot be reasonably estimated at this time.

Grynberg

     In 1998, the U.S. Department of Justice (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 would not intervene in any of the Grynberg cases. Also in 1999, the Panel on Multi-District Litigation transferred all of these cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. The District Court dismissed all claims against us and our wholly owned subsidiaries. On March 17, 2009, the Tenth Circuit Court of Appeals affirmed the District Court’s dismissal. On April 14, 2009, Grynberg filed a petition for rehearing of the Tenth Circuit’s judgment.

Notes (Continued)

Securities class actions

     Shareholder class action suits were filed against us in 2002 in the United States District Court for the Northern District of Oklahoma alleging that we and co-defendants, WilTel, previously a subsidiary known as Williams Communications, and certain corporate officers, acted jointly and separately to inflate the price of WilTel securities. WilTel was dismissed as a defendant as a result of its bankruptcy.

     In 2007, the court granted various defendants’ motions for summary judgment and entered judgment for us and the other defendants. On February 18, 2009, the Tenth Circuit Court of Appeals affirmed the lower court’s decision. The plaintiffs might request a writ of certiorari from the United States Supreme Court to appeal the Tenth Circuit’s ruling. Any obligation of ours to the WilTel equity holders as a result of a settlement, or as a result of trial in the event of a successful appeal of the court’s judgment, will not likely be covered by insurance. The extent of any such obligation is presently unknown and cannot be estimated, but it is reasonably possible that our exposure could materially exceed amounts accrued for this matter.

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 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. If the judgment is upheld on appeal, our remaining liability will be substantially less than the amount of our accrual for these matters.

Wyoming severance taxes

     In August 2006, the Wyoming Department of Audit (DOA) assessed our subsidiary, Williams Production RMT Company, additional severance tax and interest for the production years 2000 through 2002. In addition, the DOA notified us of an increase in the taxable value of our interests for ad valorem tax purposes. We disputed the DOA’s interpretation of the statutory obligation and appealed this assessment to the Wyoming State Board of Equalization (SBOE). The SBOE upheld the assessment and remanded it to the DOA to address the disallowance of a credit. We appealed to the Wyoming Supreme Court but the court ruled against us in December 2008. The negative assessment for the 2000-2002 time period resulted in additional severance and ad valorem taxes of $4 million. We have accrued a total liability of $42 million related to this matter representing our exposure, including interest, through March 31, 2009. On April 14, 2009, The Wyoming Supreme Court denied our petition for rehearing and issued its mandate affirming its prior published decision in this case.

Royalty litigation

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

Notes (Continued)

agreement for an amount that was previously accrued. We anticipate trial in 2010 on remaining issues related to royalty payment calculation and obligations under specific lease provisions. We are not able to estimate the amount of any additional exposure at this time.

     Certain other royalty matters are currently being litigated by other producers with a federal regulatory agency and with a state agency in New Mexico. Although we are not a party to these matters, the final outcome of those cases might lead to a future unfavorable impact on our results of operations.

Other Divestiture Indemnifications

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

     At March 31, 2009, 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 financial position.

Guarantees

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

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

Notes (Continued)

     We are required by certain 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 taxes required to be paid by the 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 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 $41 million at March 31, 2009. Our exposure declines systematically throughout the remaining term of WilTel’s obligations. The carrying value of these guarantees is approximately $37 million at March 31, 2009.

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

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

     We have guaranteed commercial letters of credit totaling $20 million on behalf of Accroven. These expire in January 2010 and have no carrying value.

     We have provided guarantees on behalf of certain entities in which we have an equity ownership interest. These generally guarantee operating performance measures and the maximum potential future exposure cannot be determined. There are no expiration dates associated with these guarantees. No amounts have been accrued at March 31, 2009.

Note 15. 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. Our master limited partnerships, Williams Partners L.P. and Williams Pipeline Partners L.P., are consolidated within our Midstream and Gas Pipeline segments, respectively. (See Note 2.) 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, 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.

     External revenues of our Exploration & Production segment are presented net of transportation expenses and royalties due third parties on intersegment sales. In some periods, transportation expenses and royalties due third parties on intersegment sales may exceed other external revenues.

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												Gas
		&				Gas								Marketing
		Production				Pipeline				Midstream				Services				Other				Eliminations				Total
		(Millions)
Three months ended March 31, 2009
Segment revenues:
External		$	101			$	393			$	885			$	745			$	4			$	—			$	2,128
Internal			452				8				14				122				3				(599	)			—
Total revenues		$	553			$	401			$	899			$	867			$	7			$	(599	)		$	2,128
Segment profit (loss)		$	78			$	179			$	(291	)		$	(2	)		$	1			$	—			$	(35	)
Less:
Equity earnings			4				15				4				—				—				—				23
Loss from investments			—				—				(75	)			—				—				—				(75	)
Segment operating income (loss)		$	74			$	164			$	(220	)		$	(2	)		$	1			$	—				17
General corporate expenses																											(40	)
Total operating loss																										$	(23	)
Three months ended March 31, 2008
Segment revenues:
External		$	(66	)		$	402			$	1,544			$	1,320			$	4			$	—			$	3,204
Internal			794				11				13				330				2				(1,150	)			—
Total revenues		$	728			$	413			$	1,557			$	1,650			$	6			$	(1,150	)		$	3,204
Segment profit		$	430			$	180			$	261			$	21			$	1			$	—			$	893
Less equity earnings			3				10				23				—				—				—				36
Segment operating income		$	427			$	170			$	238			$	21			$	1			$	—				857
General corporate expenses																											(42	)
Total operating income																										$	815