10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2012

or

¨ 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 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)

(918) 573-2000

Registrant’s telephone number, including area code:

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  x    No  ¨

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).    x  Yes    ¨  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	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	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  ¨    No  x

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 June 30, 2012
Common Stock, $1 par value	626,467,362 Shares

The Williams Companies, Inc.

Index

	Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Income –Three and Six Months Ended June 30, 2012 and 2011		3
Consolidated Statement of Comprehensive Income –Three and Six Months Ended June 30, 2012 and 2011		4
Consolidated Balance Sheet – June 30, 2012 and December 31, 2011		5
Consolidated Statement of Changes in Equity – Six Months Ended June 30, 2012		6
Consolidated Statement of Cash Flows – Six Months Ended June 30, 2012 and 2011		7
Notes to Consolidated Financial Statements		8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 3. Quantitative and Qualitative Disclosures About Market Risk		50
Item 4. Controls and Procedures		52
Part II. Other Information		53
Item 1. Legal Proceedings		53
Item 6. Exhibits		54

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,” “guidance,” “in service date” 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;

• Cash flow from operations or results of operations;

• The levels of dividends to stockholders;

• Seasonality of certain business components;

• 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

1

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:

• Whether we have sufficient cash to enable us to pay current and expected levels of dividends;

• Availability of supplies, 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;

• Ability to acquire new businesses and assets and integrate those operations and assets into our existing businesses, as well as expand our facilities;

• Development of alternative energy sources;

• The impact of operational and development hazards;

• Costs of, changes in, or the results of laws, government regulations (including safety and climate change regulation and changes in natural gas production from exploration and production areas that we serve), 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 and counterparties;

• 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, including cybersecurity threats and related disruptions;

• Additional risks described in our filings with the Securities and Exchange Commission (SEC).

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, 2011.

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PART I—FINANCIAL INFORMATION

The Williams Companies, Inc.

Consolidated Statement of Income

(Unaudited)

	Three months ended June 30,						Six months ended June 30,
(Millions, except per-share amounts)	2012			2011			2012			2011
Revenues:
Williams Partners	$	1,583		$	1,671		$	3,268		$	3,250
Midstream Canada & Olefins		271			347			616			663
Other		7			7			13			13
Intercompany eliminations		(15	)		(41	)		(32	)		(71	)
Total revenues		1,846			1,984			3,865			3,855
Segment costs and expenses:
Costs and operating expenses		1,350			1,398			2,701			2,709
Selling, general, and administrative expenses		105			78			198			158
Other (income) expense—net		9			3			17			(3	)
Total segment costs and expenses		1,464			1,479			2,916			2,864
General corporate expenses		50			45			90			92
Operating income (loss):
Williams Partners		312			435			770			847
Midstream Canada & Olefins		69			72			173			146
Other		1			(2	)		6			(2	)
General corporate expenses		(50	)		(45	)		(90	)		(92	)
Total operating income (loss)		332			460			859			899
Interest accrued		(140	)		(155	)		(281	)		(311	)
Interest capitalized		12			5			22			10
Investing income—net		30			40			130			84
Other income (expense)—net		3			(2	)		(1	)		4
Income (loss) from continuing operations before income taxes		237			348			729			686
Provision (benefit) for income taxes		71			109			204			87
Income (loss) from continuing operations		166			239			525			599
Income (loss) from discontinued operations		(1	)		58			135			82
Net income (loss)		165			297			660			681
Less: Net income attributable to noncontrolling interests		33			70			105			133
Net income (loss) attributable to The Williams Companies, Inc.	$	132		$	227		$	555		$	548
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations	$	133		$	171		$	420		$	471
Income (loss) from discontinued operations		(1	)		56			135			77
Net income (loss)	$	132		$	227		$	555		$	548
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	.21		$	.29		$	.69		$	.80
Income (loss) from discontinued operations		—			.10			.22			.13
Net income (loss)	$	.21		$	.39		$	.91		$	.93
Weighted-average shares (thousands)		621,483			588,310			607,357			587,641
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	.21		$	.29		$	.68		$	.79
Income (loss) from discontinued operations		—			.09			.22			.13
Net income (loss)	$	.21		$	.38		$	.90		$	.92
Weighted-average shares (thousands)		626,620			597,633			613,570			597,097
Cash dividends declared per common share	$	.300		$	.200		$	.55875		$	.325

See accompanying notes.

3

The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income

(Unaudited)

	Three months ended June 30,						Six months ended June 30,
(Millions)	2012			2011			2012			2011
Net income (loss)	$	165		$	297		$	660		$	681
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of ($14) and ($12) in 2012 and ($29) and ($21) in 2011		40			46			34			31
Reclassifications into earnings of net derivative instrument (gain) loss, net of taxes of $2 and $2 in 2012 and $25 and $53 in 2011		(5	)		(38	)		(4	)		(85	)
Foreign currency translation adjustments		(17	)		5			2			27
Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit expense		(1	)		(1	)		(1	)		(1	)
Net actuarial gain (loss) arising during the year, net of taxes of $1 and $1 in 2012		(3	)		—			(3	)		—
Amortization of actuarial (gain) loss included in net periodic benefit expense, net of taxes of ($6) and ($11) in 2012 and ($3) and ($7) in 2011		10			6			19			12
Equity securities:
Unrealized gain (loss) on equity securities, net of taxes of ($1) and ($1) in 2011		—			3			—			3
Reclassifications into earnings of (gain) loss on sale of equity securities, net of taxes of $2 in 2012		—			—			(3	)		—
Other comprehensive income (loss)		24			21			44			(13	)
Comprehensive income (loss)		189			318			704			668
Less: Comprehensive income (loss) attributable to noncontrolling interest		47			70			117			133
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	142		$	248		$	587		$	535

See accompanying notes.

4

The Williams Companies, Inc.

Consolidated Balance Sheet

(Unaudited)

(Dollars in millions, except per-share amounts)	June 30, 2012			December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	679		$	889
Accounts and notes receivable		636			637
Inventories		159			169
Regulatory assets		41			40
Other current assets and deferred charges		167			159
Total current assets		1,682			1,894
Investments		1,533			1,391
Property, plant, and equipment, at cost		20,835			19,082
Accumulated depreciation and amortization		(6,779	)		(6,502	)
Property, plant, and equipment—net		14,056			12,580
Goodwill		724			—
Other intangibles		1,662			44
Regulatory assets, deferred charges, and other		610			593
Total assets	$	20,267		$	16,502
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	695		$	691
Accrued liabilities		599			631
Long-term debt due within one year		4			353
Total current liabilities		1,298			1,675
Long-term debt		9,033			8,369
Deferred income taxes		2,555			2,157
Regulatory liabilities, deferred income, and other		1,754			1,715
Contingent liabilities (Note 13)
Equity:
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 661 million shares issued at June 30, 2012 and 626 million shares issued at December 31, 2011)		661			626
Capital in excess of par value		9,305			7,920
Retained deficit		(5,607	)		(5,820	)
Accumulated other comprehensive income (loss)		(357	)		(389	)
Treasury stock, at cost (35 million shares of common stock)		(1,041	)		(1,041	)
Total stockholders’ equity		2,961			1,296
Noncontrolling interests in consolidated subsidiaries		2,666			1,290
Total equity		5,627			2,586
Total liabilities and equity	$	20,267		$	16,502

See accompanying notes.

5

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity

(Unaudited)

	The Williams Companies, Inc., Stockholders
	Common Stock				Capital in Excess of Par Value			Retained Deficit				Accumulated Other Comprehensive Income (loss)				Treasury Stock				Total Stockholders’ Equity				Noncontrolling Interest				Total
	(Millions)
Balance—December 31, 2011		$	626			$	7,920		$	(5,820	)		$	(389	)		$	(1,041	)		$	1,296			$	1,290			$	2,586
Net income (loss)			—				—			555				—				—				555				105				660
Other comprehensive income (loss)			—				—			—				32				—				32				12				44
Cash dividends – common stock			—				—			(342	)			—				—				(342	)			—				(342	)
Dividends and distributions to noncontrolling interests			—				—			—				—				—				—				(190	)			(190	)
Issuance of common stock from debentures conversion			1				5			—				—				—				6				—				6
Stock-based compensation, net of tax			5				62			—				—				—				67				—				67
Sale of limited partner units of Williams Partners L.P.			—				—			—				—				—				—				1,071				1,071
Issuance of limited partner units of Williams Partners L.P. related to acquisitions			—				—			—				—				—				—				1,044				1,044
Changes in Williams Partners L.P. ownership interest, net			—				460			—				—				—				460				(733	)			(273	)
Sale of common stock			30				857			—				—				—				887				—				887
Reconsolidation of noncontrolling interest in Wilpro entities (see Note 3)			—				—			—				—				—				—				65				65
Other			(1	)			1			—				—				—				—				2				2
Balance—June 30, 2012		$	661			$	9,305		$	(5,607	)		$	(357	)		$	(1,041	)		$	2,961			$	2,666			$	5,627

See accompanying notes.

6

The Williams Companies, Inc.

Consolidated Statement of Cash Flows

(Unaudited)

	Six months ended June 30,
(Millions)	2012			2011
OPERATING ACTIVITIES:
Net income (loss)	$	660		$	681
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation, depletion, and amortization		349			784
Provision (benefit) for deferred income taxes		117			87
Provision for loss on investments, property and other assets		—			51
Net (gain) loss on dispositions of assets		(61	)		(6	)
Gain on reconsolidation of Wilpro entities (Note 3)		(144	)		—
Amortization of stock-based awards		18			25
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable		88			(56	)
Inventories		10			20
Margin deposits and customer margin deposits payable		26			(30	)
Other current assets and deferred charges		39			(9	)
Accounts payable		(174	)		109
Accrued liabilities		(41	)		30
Other, including changes in noncurrent assets and liabilities		(29	)		(2	)
Net cash provided (used) by operating activities		858			1,684
FINANCING ACTIVITIES:
Proceeds from long-term debt		500			425
Payments of long-term debt		(180	)		(225	)
Proceeds from issuance of common stock		928			29
Proceeds from sale of limited partner units of consolidated partnership		1,071			—
Dividends paid		(342	)		(191	)
Dividends and distributions paid to noncontrolling interests		(152	)		(105	)
Distributions paid to noncontrolling interests on sale of Wilpro assets (Note 3)		(38	)		—
Other – net		35			(47	)
Net cash provided (used) by financing activities		1,822			(114	)
INVESTING ACTIVITIES:
Capital expenditures*		(922	)		(1,094	)
Contributions to equity method investments		(184	)		(109	)
Purchases of businesses		(2,049	)		—
Proceeds from dispositions of investments		78			11
Cash of Wilpro entities upon reconsolidation (Note 3)		121			—
Other – net		66			(7	)
Net cash provided (used) by investing activities		(2,890	)		(1,199	)
Increase (decrease) in cash and cash equivalents		(210	)		371
Cash and cash equivalents at beginning of period		889			795
Cash and cash equivalents at end of period	$	679		$	1,166
*        Increases to property, plant, and equipment	$	(999	)	$	(1,086	)
Changes in related accounts payable and accrued liabilities		77			(8	)
Capital expenditures	$	(922	)	$	(1,094	)

See accompanying notes.

7

The Williams Companies, Inc.

Notes to Consolidated Financial Statements

(Unaudited)

Note 1. General, Description of Business and Basis of Presentation

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 Form 10-K/A Amendment No. 2, filed May 1, 2012. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements.

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.

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us,” or similar language refer to The Williams Companies, Inc. and its subsidiaries.

Description of Business

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

Williams Partners consists of our consolidated master limited partnership, Williams Partners L.P. (WPZ) and includes 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 50 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 the Marcellus Shale region, and various equity investments in domestic natural gas gathering and processing assets and natural gas liquid (NGL) fractionation and transportation assets. WPZ’s midstream assets also include substantial operations and investments in the Four Corners region, the Piceance basin, as well as an NGL fractionator and storage facilities near Conway, Kansas.

Our Midstream Canada & Olefins segment includes our oil sands offgas 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, as well as corporate operations.

Basis of Presentation

Master limited partnership

During the first quarter of 2012, WPZ completed a public equity issuance of 8,050,000 common units representing limited partner interests. WPZ also issued 7,531,381 common units to the seller in connection with its acquisition of certain entities from Delphi Midstream Partners, LLC. (See Note 2). During the second quarter of 2012, WPZ completed a public equity issuance of 10,973,368 common units representing limited partner interests. WPZ also issued 11,779,296 common units to the seller in connection with its acquisition of Caiman Eastern Midstream, LLC (See Note 2). In connection with the closing of this acquisition, we purchased 16,360,133 additional WPZ common units. Following these transactions, as of June 30, 2012, we own approximately 68 percent of the interests in WPZ, including the interests of the general partner, which are wholly owned by us, and incentive distribution rights.

8

Notes (Continued)

The previously described equity issuances by WPZ had the combined net impact of increasing our noncontrolling interests in consolidated subsidiaries by $1.382 billion, capital in excess of par value by $460 million and deferred income taxes by $273 million in the Consolidated Balance Sheet.

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.

Variable interest entity

Gulfstar One (Gulfstar) is a consolidated wholly-owned subsidiary that, due to certain risk sharing provisions in its customer contracts, is a variable interest entity. WPZ, as construction agent for Gulfstar, will design, construct, and install a proprietary floating-production system, Gulfstar FPS™, and associated pipelines which will initially provide production handling and gathering services for the Tubular Bells oil and gas discovery in the eastern deepwater Gulf of Mexico. Construction is underway and the project is expected to be in service in 2014. WPZ, in combination with certain advance payments from the producer customers, is currently financing the asset construction. As of June 30, 2012, the Consolidated Balance Sheet includes $305 million of Gulfstar construction work in process representing costs incurred to date, included in property, plant, and equipment, at cost and $110 million of deferred revenue, included in regulatory liabilities, deferred income, and other associated with the customer advance payments. We are committed to the producer customers to construct this system and we currently estimate the remaining construction cost to be less than $650 million. If the producer customers do not develop the offshore oil and gas fields to be connected to Gulfstar, they will be responsible for the firm price of building the facilities.

Discontinued operations

On December 31, 2011, we completed the tax-free spin-off of our 100 percent interest in WPX Energy, Inc. (WPX), to our shareholders. The spin-off was completed by means of a special stock dividend, which consisted of a distribution of one share of WPX common stock for every three shares of our common stock. For periods prior to the spin-off, the accompanying Consolidated Statement of Income reflects the results of operations of our former exploration and production business as discontinued operations. (See Note 3.)

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

Note 2. Acquisitions

On February 17, 2012, WPZ completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC, in exchange for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments, and 7,531,381 WPZ common units valued at $441 million (Laser Acquisition). The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of WPZ’s common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entities primarily own the Laser Gathering System, which is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as 10 miles of gathering lines in southern New York.

On April 27, 2012, WPZ completed the acquisition of 100 percent of the ownership interests in Caiman Eastern Midstream, LLC, from Caiman Energy, LLC (Caiman Acquisition) in exchange for $1.72 billion in cash, net of purchase price adjustments, and 11,779,296 WPZ common units valued at $603 million. The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of WPZ’s common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entity operates a gathering and processing business in northern West Virginia, southwestern Pennsylvania and eastern Ohio. Acquisition transaction costs of $16 million were incurred related to the Caiman Acquisition and are reported in selling, general and administrative expenses at Williams Partners in the Consolidated Statement of Income.

9

Notes (Continued)

These acquisitions were accounted for as business combinations which, among other things, require assets acquired and liabilities assumed to be measured at their acquisition-date fair values. The excess of cost over those fair values was allocated to goodwill within the Williams Partners segment.

The amounts recognized in the financial statements are preliminary because our valuation work has not been completed. For the Laser Acquisition, we are awaiting further information for valuing intangible assets, contingent liabilities and asset retirement obligations. For the Caiman Acquisition, we are awaiting further information for valuing the working capital components, property, plant and equipment, intangible assets, contingent liabilities and asset retirement obligations. In addition, we are still in the process of identifying all the assets acquired and liabilities assumed.

The following table presents a preliminary allocation of the acquisition-date fair value of the major classes of the net assets, which are presented in the Williams Partners segment:

	Laser			Caiman
Assets held for sale	$	18		$	—
Other current assets		3			13
Property, plant and equipment		158			665
Intangible assets		318			1,313
Current liabilities		(21	)		(98	)
Identifiable net assets acquired		476			1,893
Goodwill		290			434
	$	766		$	2,327

Identifiable intangible assets recognized to date in the acquisitions are primarily related to gas gathering, processing and fractionation agreements and relationships with customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired customer contracts and relationships, which are offset with appropriate charges for the use of contributory assets and discounted using a risk-adjusted discount rate. Those intangible assets are being amortized on a straight-line basis over an initial 30-year period during which the customer contracts and relationships are expected to contribute to our cash flows. We expense costs incurred to renew or extend the terms of our gas gathering, processing and fractionation agreements with customers.

We will evaluate these intangible assets for both changes in the expected remaining useful lives and impairment when events or changes in circumstances indicate, in our management’s judgment, that the estimated useful lives have changed or the carrying value of such assets may not be recoverable. Changes in an estimated remaining useful life would be reflected prospectively through amortization over the revised remaining useful life. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the intangible assets to the carrying value of the assets to determine whether an impairment has occurred and we apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

10

Notes (Continued)

Goodwill recognized in the acquisitions relates primarily to enhancing our strategic platform for expansion in the area. We are currently evaluating the appropriate reporting unit for the allocation of the goodwill within the Williams Partners segment. The goodwill is not subject to amortization but will be evaluated annually for impairment or more frequently if impairment indicators are present. Our evaluation will include a qualitative assessment of events or circumstances to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount. If so, we will further compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss will be recognized in the amount of the excess. All of the goodwill is expected to be deductible for tax purposes.

Revenues and earnings related to the Laser and Caiman Acquisitions included within the Consolidated Statement of Income since the respective acquisition dates are not material. Supplemental pro forma revenue and earnings reflecting these acquisitions as if they had occurred as of January 1, 2011, are not materially different from the information presented in our accompanying Consolidated Statement of Income (since the historical operations of these acquisitions were insignificant relative to our historical operations) and are, therefore, not presented.

Note 3. Discontinued Operations

On December 31, 2011, we completed the tax-free spin-off of our 100 percent interest in WPX to our shareholders. At December 31, 2011, the net assets of our former exploration and production business were eliminated from our consolidated balance sheet as the spin-off was complete.

The following summarized results of discontinued operations for 2011 reflect the results of operations of our former exploration and production business as discontinued operations. The summarized results of discontinued operations for 2012 primarily include a gain on reconsolidation following the sale of certain of our former Venezuela operations, whose facilities were expropriated by the Venezuelan government in May 2009.

Summarized Results of Discontinued Operations

	Three months ended June 30,						Six months ended June 30,
	2012			2011			2012			2011
	(Millions)
Revenues	$	—		$	985		$	—		$	1,977
Income (loss) from discontinued operations before gain on reconsolidation, impairment and income taxes	$	(2	)	$	97		$	(10	)	$	143
Gain on reconsolidation		—			—			144			—
Impairment		—			(2	)		—			(11	)
(Provision) benefit for income taxes		1			(37	)		1			(50	)
Income (loss) from discontinued operations	$	(1	)	$	58		$	135		$	82
Income (loss) from discontinued operations:
Attributable to noncontrolling interests	$	—		$	2		$	—		$	5
Attributable to The Williams Companies, Inc.	$	(1	)	$	56		$	135		$	77

Gain on reconsolidation for 2012 is related to our majority ownership in entities (the Wilpro entities) that owned and operated the El Furrial and PIGAP II gas compression facilities prior to their expropriation by the Venezuelan government in May 2009. We deconsolidated the Wilpro entities in 2009. In the first quarter of 2012, the El Furrial and PIGAP II assets were sold as part of a settlement related to the 2009 expropriation of these assets. Upon closing, the lenders that had provided financing for these operations were repaid in full, and the Wilpro entities received $98 million in cash and the right to receive quarterly cash installments of $15 million (note receivable) through the first quarter of 2016 plus interest. Following the settlement and repayment in full of the

11

Notes (Continued)

lenders, we reestablished control and, therefore, reconsolidated the Wilpro entities and recognized a gain on reconsolidation of $144 million. This gain reflects our share of the cash, including cash received in the settlement, and a note receivable held by the Wilpro entities at the time of reconsolidation. The note receivable was recognized at its estimated fair value, as further described below.

To determine the fair value of the note receivable at the time of reconsolidation, we considered both quantitative (income) and qualitative (market) approaches. Under our quantitative approach, we calculated the net present value of a probability-weighted set of cash flows utilizing assumptions based on contractual terms, historical payment patterns by the counterparty under similar circumstances, our likelihood of using arbitration if the counterparty does not perform, and discount rates. Our qualitative analysis utilized information as to how similar notes might be valued. This analysis also reduced the value due to its limited marketability as the payment terms are embedded within the overall settlement agreement. Both analyses resulted in similar fair values. Ultimately we determined the fair value of the note receivable to be $88 million at the time of reconsolidation, utilizing a probability-weighted cash flow analysis with a discount rate of approximately 12 percent and a probability of default ranging from 15 percent to 100 percent. Utilizing different assumptions regarding the collectability of the note receivable and discount rates could result in a materially different fair value. See Note 11 for a further discussion of this note receivable.

Revenues and income (loss) from discontinued operations before gain on reconsolidation, impairment and income taxes for 2011 primarily reflects the results of operations of our discontinued exploration and production business.

Energy Commodity Derivatives Gains and Losses

The following table presents pre-tax gains and losses for the three months and six months ended June 30, 2011, for our former exploration and production business’ energy commodity derivatives.

	Three months ended June 30, 2011		Six months ended June 30, 2011		Classification
	(Millions)
Designated as cash flow hedges
Net gain (loss) recognized in other comprehensive income (loss) (effective portion)	$	79	$	58	Accumulated other comprehensive income (loss) (AOCI)
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$	67	$	142	Income (loss) from discontinued operations
Gain (loss) recognized in income (ineffective portion)	$	—	$	—	Income (loss) from discontinued operations
Not designated as cash flow hedges
Gain (loss) recognized in income	$	3	$	6	Income (loss) from discontinued operations

Note 4. Asset Sales and Other Accruals

Other (income) expense – net within segment costs and expenses in the six months ended June 30, 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. This reversal was made upon determining that the related project was probable of development. These costs are now included in the capital costs of the project, which we believe are probable of recovery through the project rates.

12

Notes (Continued)

Investing income – net at Other includes income of $63 million and $11 million in the six months ended June 30, 2012 and 2011, respectively, related to the 2010 sale of our interest in Accroven SRL. As part of a settlement regarding certain Venezuelan assets in the first quarter of 2012 (see Note 3), we also received payment for all outstanding balances due from this sale, including interest. Payments were recognized upon receipt, as future collections were not reasonably assured.

13

Notes (Continued)

Note 5. Provision (Benefit) for Income Taxes

The provision (benefit) for income taxes includes:

	Three months ended June 30,					Six months ended June 30,
	2012			2011		2012			2011
	(Millions)					(Millions)
Current:
Federal	$	33		$	59	$	54		$	88
State		4			5		8			8
Foreign		3			14		24			(6	)
		40			78		86			90
Deferred:
Federal		30			25		117			(7	)
State		(3	)		2		(6	)		(1	)
Foreign		4			4		7			5
		31			31		118			(3	)
Total provision (benefit)	$	71		$	109	$	204		$	87

The effective income tax rate for the total provision for the three months ended June 30, 2012 is less than the federal statutory rate primarily due to the impact of nontaxable noncontrolling interests.

The effective income tax rate for the total provision for the six months ended June 30, 2012 is less than the federal statutory rate primarily due to the impact of nontaxable noncontrolling interests and taxes on foreign operations.

The effective income tax rate for the total provision for the three months ended June 30, 2011 is less than the federal statutory rate primarily due to the impact of nontaxable noncontrolling interests and taxes on foreign operations, partially offset by the effect of state income taxes.

The effective income tax rate for the total provision for the six months ended June 30, 2011 is less than the federal statutory rate primarily due to federal settlements, an international revised assessment, and the impact of nontaxable noncontrolling interests and taxes on foreign operations, partially offset by the effect of state income taxes.

During the first quarter of 2011, we finalized settlements for 1997 through 2008 on certain contested matters with the Internal Revenue Service and also received a revised assessment on an international matter. These settlements and revised assessment resulted in a tax benefit of approximately $124 million for the six months ended June 30, 2011. As a result of these settlements and revised assessment, we decreased our unrecognized tax benefits by approximately $62 million during the first quarter of 2011.

On December 23, 2011, the Internal Revenue Service issued temporary and proposed regulations providing guidance relating to the deduction and capitalization of expenditures made to acquire, produce, or improve tangible property. These regulations, effective January 1, 2012, will generally require changes in accounting methods. Once complete guidance has been released, we will assess the impact of the regulations on our Consolidated Financial Statements.

During the next 12 months, we do not expect ultimate resolution of any unrecognized tax benefit associated with domestic or international matters to have a material impact on our unrecognized tax benefit position.

14

Notes (Continued)

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

	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
	(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	$	133	$	171	$	420	$	471
Basic weighted-average shares		621,483		588,310		607,357		587,641
Effect of dilutive securities:
Nonvested restricted stock units		2,109		3,887		2,836		4,005
Stock options		2,614		3,537		2,776		3,501
Convertible debentures		414		1,899		601		1,950
Diluted weighted-average shares		626,620		597,633		613,570		597,097
Earnings (loss) per common share from continuing operations:
Basic	$	.21	$	.29	$	.69	$	.80
Diluted	$	.21	$	.29	$	.68	$	.79

Effective January 1, 2012, new awards of time-based restricted stock units contain a nonforfeitable right to dividends during the vesting period. These share-based payment awards are participating securities and are included in the computation of earnings (loss) per common share pursuant to the two-class method. The impact for the three and six months ended June 30, 2012, is immaterial.

The table below includes information related to stock options that were outstanding at June 30 of each respective year but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the second quarter weighted-average market price of our common shares.

	June 30,
	2012		2011
Options excluded (millions)		—		1.0
Weighted-average exercise price of options excluded		N/A	$	36.47
Exercise price ranges of options excluded		N/A	$	32.05—$37.88
Second quarter weighted-average market price	$	30.93	$	30.54

Note 7. Employee Benefit Plans

Net periodic benefit expense is as follows:

	Pension Benefits
	Three months ended June 30,						Six months ended June 30,
	2012			2011			2012			2011
	(Millions)
Components of net periodic benefit expense:
Service cost	$	9		$	10		$	19		$	20
Interest cost		14			15			28			32
Expected return on plan assets		(16	)		(19	)		(32	)		(38	)
Amortization of net actuarial loss		14			10			27			19
Net actuarial loss from settlements		2			—			2			—
Net periodic benefit expense	$	23		$	16		$	44		$	33

15

Notes (Continued)

	Other Postretirement Benefits
	Three months ended June 30,						Six months ended June 30,
	2012			2011			2012			2011
	(Millions)
Components of net periodic benefit expense:
Service cost	$	—		$	—		$	1		$	1
Interest cost		3			3			6			7
Expected return on plan assets		(2	)		(2	)		(4	)		(5	)
Amortization of prior service cost (credit)		(1	)		(2	)		(3	)		(5	)
Amortization of net actuarial loss		1			1			4			2
Net periodic benefit expense	$	1		$	—		$	4		$	—

During the six months ended June 30, 2012, we contributed $38 million to our pension plans and $7 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $41 million to our pension plans and approximately $8 million to our other postretirement benefit plans in the remainder of 2012.

Note 8. Inventories

	June 30, 2012		December 31, 2011
	(Millions)
Natural gas liquids, olefins, and natural gas in underground storage	$	86	$	98
Materials, supplies, and other		73		71
	$	159	$	169

Note 9. Debt and Banking Arrangements

Credit Facilities

Letter of credit capacity under our $900 million and WPZ’s $2 billion credit facilities is $700 million and $1.3 billion, respectively. At June 30, 2012, no letters of credit have been issued on either facility. No loans are outstanding on our credit facility at June 30, 2012. Loans totaling $345 million are outstanding on WPZ’s credit facility at June 30, 2012. We have issued letters of credit totaling $24 million as of June 30, 2012, under certain bilateral bank agreements.

Issuances and Retirements

In July 2012, Transco issued $400 million of 4.45 percent senior unsecured notes due 2042 to investors in a private debt placement. A portion of these proceeds was used to repay Transco’s $325 million 8.875 percent senior unsecured notes that matured on July 15, 2012. As a result of this transaction, we presented the $325 million notes as long-term debt at June 30, 2012. As part of the new issuance, Transco entered into a registration rights agreement with the initial purchasers of the unsecured notes. Transco is obligated to file a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 180 days from closing and to use commercially reasonable efforts to cause the registration statement to be declared effective within 270 days after closing and to consummate the exchange offer within 30 business days after such effective date. Transco is required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If Transco fails to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25 percent per annum on the principal amount of

16

Notes (Continued)

the affected securities for the first 90-day period immediately following the occurrence of default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such defaults of 0.5 percent annually. Following the cure of any registration defaults, the accrual of additional interest will cease.

In August 2011, Transco issued $375 million of 5.4 percent senior unsecured notes due 2041 to investors in a private debt placement. As part of the new issuance, Transco entered into a registration rights agreement with the initial purchasers of the notes. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in February 2012 and completed in March 2012.

Note 10. Stockholders’ Equity

In April 2012, we issued 30 million shares of common stock in a public offering at a price of $30.59 per share. We used the net proceeds of $887 million to fund a portion of the purchase of additional WPZ common units in connection with WPZ’s Caiman Acquisition. (See Note 2.)

Note 11. Fair Value Measurements

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.

							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at June 30, 2012:
Measured on a recurring basis:
ARO Trust investments	$	25		$	25		$	25		$	—		$	—
Energy derivatives assets not designated as hedging instruments		5			5			2			3			—
Energy derivatives assets designated as hedging instruments		41			41			29			12			—
Energy derivatives liabilities not designated as hedging instruments		(5	)		(5	)		(3	)		(2	)		—
Additional disclosures:
Notes receivable and other		131			133			6			9			118
Long-term debt, including current portion (a)		(9,034	)		(10,426	)		—			(10,426	)		—
Guarantee		(33	)		(31	)		—			(31	)		—
Customer margin deposits payable		(32	)		(32	)		(32	)		—			—
Assets (liabilities) at December 31, 2011:
Measured on a recurring basis:
ARO Trust investments	$	25		$	25		$	25		$	—		$	—
Available-for-sale equity securities		24			24			24			—			—
Energy derivatives assets not designated as

17

Notes (Continued)

hedging instruments	1		1		1	—	—
Additional disclosures:
Notes receivable and other	57		57		N/A	N/A	N/A
Long-term debt, including current portion (a)	(8,718	)	(10,043	)	N/A	N/A	N/A
Guarantee	(34	)	(32	)	N/A	N/A	N/A

(a) Excludes capital leases

Fair Value Methods

We use the following methods and assumptions in estimating the fair value of our financial instruments:

Assets and liabilities measured at fair value on a recurring basis

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

Energy derivatives: Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) contracts, which consist solely of swaps that are measured at fair value on a recurring basis. The tenure of our energy derivatives portfolio is relatively short with all of our energy derivatives expiring in the next nine 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 do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives are reported in other current assets and deferred charges and accrued liabilities in the Consolidated Balance Sheet.

Energy derivatives considered Level 1 measurements consist of New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets.

Energy derivatives included in our Level 2 measurements consist solely of OTC swaps. Swap contracts included in Level 2 are valued using an income approach including present value techniques. Significant inputs into our Level 2 valuations include commodity prices 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.

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 transfers between Level 1 and Level 2 occurred during the six months ended June 30, 2012 or 2011.

Additional fair value disclosures

Notes receivable and other: Notes receivable and other includes a note receivable related to the sale of certain former Venezuela assets. The disclosed fair value of this note receivable uses an approach and assumptions consistent with that used at initial recognition (see Note 3), updated to consider receipt of the first scheduled payment. The carrying value and disclosed fair value of this note is $75 million and $78 million, respectively, at June 30, 2012. The current and noncurrent portions are reported in accounts and notes receivable and regulatory assets, deferred charges, and other, respectively, in the Consolidated Balance Sheet.

18

Notes (Continued)

Notes receivable and other, also includes a receivable from our former affiliate, WPX (see Note 13), and other notes receivable. The disclosed fair value of these receivables is determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current and noncurrent portions are reported in accounts and notes receivable and regulatory assets, deferred charges, and other, respectively, in the Consolidated Balance Sheet.

Long-term debt: The disclosed fair value of our long-term debt is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.

Guarantee: The guarantee represented in the 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 that extends through 2042.

To estimate the disclosed fair value of the guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. 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 rate is published by Moody’s Investors Service. This guarantee is reported in accrued liabilities in the Consolidated Balance Sheet.

Customer margin deposits payable: The disclosed fair value of our customer margin deposits payable is considered to approximate the carrying value generally due to the short-term nature of these items, and are reported in accrued liabilities in the Consolidated Balance Sheet.

Guarantees

We are required by our revolving credit agreements to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain 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.

Regarding our previously described guarantee of Wiltel’s lease performance, the maximum potential exposure is approximately $37 million at June 30, 2012 and $38 million at December 31, 2011. Our exposure declines systematically throughout the remaining term of WilTel’s obligation.

We have provided guarantees in the event of nonpayment by our previously owned subsidiary, WPX, on certain contracts, primarily including a long-term transportation capacity agreement and a natural gas purchase contract, extending through 2017 and 2023, respectively. We estimate the maximum undiscounted potential future payment obligation under these remaining guarantees is approximately $245 million at June 30, 2012. Our recorded liability for these guarantees, which considers our estimate of the fair value of the guarantees, is insignificant.

Note 12. Derivative Instruments

Energy Commodity Derivatives

Risk management activities

We are exposed to market risk from changes in energy commodity prices within our operations. We 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.

19

Notes (Continued)

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. In addition, we buy NGLs as feedstock to generate 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.

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 two types:

• Central hub risk: Includes physical and financial derivative exposures to Henry Hub for natural gas 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.

The following table depicts the notional quantities of the net long (short) positions in our commodity derivatives portfolio as of June 30, 2012. Natural gas is presented in millions of British Thermal Units (MMBtu) and NGLs are presented in barrels.

Derivative Notional Volumes	Unit of Measure		Central Hub Risk			Basis Risk
Designated as Hedging Instruments
Williams Partners		Barrels		(1,770,000	)
Williams Partners		MMBtu		7,810,800			6,504,400
Not Designated as Hedging Instruments
Williams Partners		Barrels		115,000			255,000
Midstream Canada & Olefins		Barrels		(220,000	)

Gains (losses)

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 June 30,					Six months ended June 30,
	2012		2011			2012		2011			Classification
	(Millions)					(Millions)
Net gain (loss) recognized in other comprehensive income (loss) (effective portion)	$	55	$	(4	)	$	46	$	(6	)	AOCI
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$	8	$	(4	)	$	6	$	(4	)	Revenues or Costs and Operating Expenses

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

20

Notes (Continued)

We recognized gains of $3 million and losses of $1 million in revenues for the six months ended June 30, 2012 and 2011, respectively, on our energy commodity derivatives not designated as hedging instruments. We also recognized gains of $2 million and losses of less than $1 million in revenues for the three months ended June 30, 2012 and 2011, respectively, on our energy commodity derivatives not designated as hedging instruments. In addition, we recognized gains of less than $1 million in costs and operating expenses for the six months ended June 30, 2012, on our energy commodity derivatives not designated as hedging instruments.

The cash flow impact of our derivative activities is presented in the Consolidated Statement of Cash Flows as other, including changes in noncurrent 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.

At both June 30, 2012, and December 31, 2011, we did not have any collateral posted, either in the form of cash or letters of credit, to derivative counterparties.

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 June 30, 2012, we have hedged portions of future cash flows associated with anticipated energy commodity purchases and sales through the end of 2012. Based on recorded values at June 30, 2012, $40 million of pre-tax net gains will be reclassified into earnings within the next six months. These recorded values are based on market prices of the commodities as of June 30, 2012. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized within the next six months 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 13. Contingent Liabilities

Indemnification of WPX Matters

We have agreed to indemnify our former affiliate, WPX and its subsidiaries, related to the following matters. In connection with this indemnification, we have retained applicable accrued asset and liability balances associated with these matters, and as a result, have an indirect exposure to future developments in these matters.

Issues resulting from California energy crisis

WPX’s former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by WPX 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). WPX has 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.

21

Notes (Continued)

Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, WPX continues to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. WPX is 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 WPX’s collection of accrued interest from counterparties as well as their payment of accrued interest on refund amounts. Thus, as currently contemplated by the parties, the settlement agreement would resolve most, if not all, of WPX’s legal issues arising from the 2000-2001 California Energy Crisis. We currently have a net receivable from WPX related to these matters.

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 WPX and others, in each case seeking an unspecified amount of damages. WPX is 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 WPX and most of the other defendants based on plaintiffs’ lack of standing. In 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in WPX’s favor. The court’s order became final on July 18, 2011, and the Colorado plaintiffs might appeal the order.

In the other cases, on July 18, 2011, the Nevada district court granted WPX’s joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. In 2011, the plaintiffs’ appealed the court’s ruling to the Ninth Circuit Court of Appeals, and in early 2012, the parties completed briefing the issues. A decision is expected in 2013. 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 and our related indemnification obligation could result in future charges that may be material to our results of operations.

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

22

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 accrued 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. As a result, we reduced our accrued liability as of December 31, 2011 by $33 million, including $14 million of interest. The Texas Court of Appeals also reversed and remanded the contract claim and attorney fee claims for further proceedings. None of the parties filed a petition for review in the Texas Supreme Court. On May 8, 2012, the Texas Court of Appeals issued its mandate remanding the case to the trial court.

Alaska refinery contamination litigation

In January 2010, James West filed a class action lawsuit in state court in Fairbanks, Alaska on behalf of individual property owners whose water contained sulfolane contamination allegedly emanating from the Flint Hills Oil Refinery in North Pole, Alaska. The suit named our subsidiary, Williams Alaska Petroleum Inc. (WAPI), and Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., as defendants. We owned and operated the refinery until 2004 when we sold it to FHRA. We and FHRA have made claims under the pollution liability insurance policy issued in connection with the sale of the North Pole refinery to FHRA. We and FHRA also filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination.

In August 2010, the court denied West’s request for class certification. On May 5, 2011, we and FHRA settled the James West claim, leaving FHRA and WAPI claims. On November 17, 2011, we filed motions for summary judgment on FHRA’s claims against us, but the motions are unlikely to resolve all the outstanding claims. Similarly, FHRA has filed motions for summary judgment that would resolve some, but not all, of our claims against it. Trial is set for April 2013.

While significant uncertainty still exists due to, among other things, ongoing proceedings and expert evaluations, we currently estimate that our reasonably possible loss exposure in this matter could range from an insignificant amount up to $32 million. We might have the ability to recover any such losses under the pollution liability policy if FHRA has not exhausted the policy limits.

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.

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. 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. As of June 30, 2012, we have accrued liabilities totaling $45 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated

23

Notes (Continued)

at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered and the final cleanup standards mandated by the EPA and other governmental authorities.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent 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.

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 EPA, various state environmental authorities and identification as a potentially responsible party at various Superfund waste disposal sites. At June 30, 2012, we have accrued liabilities of $9 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 June 30, 2012, we have accrued liabilities totaling $8 million for these costs.

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;

• Former petroleum refining facilities;

• Former exploration and production and mining operations;

• Former electricity and natural gas marketing and trading operations.

At June 30, 2012, we have accrued environmental liabilities of $28 million related to these matters.

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 June 30, 2012, other than as previously disclosed, we are not aware of any material claims involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.

24

Notes (Continued)

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

Summary

We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.

Note 14. Segment Disclosures

Our reporting segments are Williams Partners and Midstream Canada & Olefins. All remaining business activities are included in Other. (See Note 1.)

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;

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

As discussed in Notes 1 and 3, our former exploration and production business was spun-off on December 31, 2011 and has been reported as discontinued operations in all prior periods presented. Revenues derived from intercompany sales to our former exploration and production business, previously reported as internal, have been recast and are now shown as external. These sales were $78 million and $152 million for the three months and six months ended June 30, 2011, respectively. In addition, costs attributable to activities with our former exploration and production business, previously reported as internal, have been recast and are now shown as external. Such costs were $219 million and $429 million for the three months and six months ended June 30, 2011, respectively.

25

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 Income and total assets by reporting segment.

	Williams Partners		Midstream Canada & Olefins			Other			Eliminations			Total
	(Millions)
Three months ended June 30, 2012
Segment revenues:
External	$	1,573	$	269		$	4		$	—		$	1,846
Internal		10		2			3			(15	)		—
Total revenues	$	1,583	$	271		$	7		$	(15	)	$	1,846
Segment profit (loss)	$	339	$	68		$	1		$	—		$	408
Less:
Equity earnings (losses)		27		—			—			—			27
Income (loss) from investments		—		(1	)		—			—			(1	)
Segment operating income (loss)	$	312	$	69		$	1		$	—			382
General corporate expenses													(50	)
Total operating income (loss)												$	332
Three months ended June 30, 2011
Segment revenues:
External	$	1,636	$	345		$	3		$	—		$	1,984
Internal		35		2			4			(41	)		—
Total revenues	$	1,671	$	347		$	7		$	(41	)	$	1,984
Segment profit (loss)	$	471	$	72		$	2		$	—		$	545
Less:
Equity earnings (losses)		36		—			4			—			40
Segment operating income (loss)	$	435	$	72		$	(2	)	$	—			505
General corporate expenses													(45	)
Total operating income (loss)												$	460
Six months ended June 30, 2012
Segment revenues:
External	$	3,246	$	612		$	7		$	—		$	3,865
Internal		22		4			6			(32	)		—
Total revenues	$	3,268	$	616		$	13		$	(32	)	$	3,865
Segment profit (loss)	$	827	$	171		$	60		$	—		$	1,058
Less:
Equity earnings (losses)		57		—			1			—			58
Income (loss) from investments		—		(2	)		53			—			51
Segment operating income (loss)	$	770	$	173		$	6		$	—			949
General corporate expenses													(90	)
Total operating income (loss)												$	859
Six months ended June 30, 2011
Segment revenues:
External	$	3,188	$	660		$	7		$	—		$	3,855
Internal		62		3			6			(71	)		—
Total revenues	$	3,250	$	663		$	13		$	(71	)	$	3,855
Segment profit (loss)	$	908	$	146		$	22		$	—		$	1,076
Less:
Equity earnings (losses)		61		—			13			—			74
Income (loss) from investments		—		—			11			—			11
Segment operating income (loss)	$	847	$	146		$	(2	)	$	—			991
General corporate expenses													(92	)
Total operating income (loss)												$	899
June 30, 2012
Total assets (a)	$	18,040	$	1,262		$	1,303		$	(338	)	$	20,267
December 31, 2011
Total assets	$	14,380	$	1,138		$	1,275		$	(291	)	$	16,502

(a) The increase in Williams Partners’ total assets as compared to the prior year-end is substantially due to the acquisition of certain entities from Delphi Midstream Partners, LLC in the first quarter of 2012 and the acquisition of Caiman Eastern Midstream, LLC in the second quarter of 2012. (See Note 2.)

26

Item 2

Management’s Discussion and Analysis of

Financial Condition and Results of Operations

General

We are primarily an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas, natural gas liquids (NGLs), and olefins. Our operations are located principally in the United States, but span from the deepwater Gulf of Mexico to the Canadian oil sands, and are organized into the Williams Partners and Midstream Canada & Olefins reporting segments. All remaining business activities are included in Other. (See Note 1 of Notes to Consolidated Financial Statements for further discussion of these segments.) The Williams Partners segment consists of our consolidated master limited partnership, Williams Partners L.P. (WPZ), of which we currently own approximately 68 percent, including the general partner interest.

Unless indicated otherwise, the following discussion and analysis of critical accounting estimates, results of operations, and financial condition and liquidity 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 Amendment No. 2 to our 2011 Annual Report on Form 10-K/A, filed May 1, 2012.

Acquisitions

In February 2012, WPZ completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC (Laser Acquisition). These entities primarily own the Laser Gathering System, which is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as 10 miles of gathering lines in southern New York. This acquisition represents a strategic platform to enhance WPZ’s expansion in the Marcellus Shale by providing our customers with both operational flow assurance and marketing flexibility. (See Results of Operations – Segments, Williams Partners.)

In April 2012, WPZ completed the acquisition of 100 percent of the ownership interest in Caiman Eastern Midstream, LLC (Caiman Acquisition). The acquired entity operates a gathering and processing business in northern West Virginia, southwestern Pennsylvania and eastern Ohio. WPZ believes this acquisition will provide it with a significant footprint and growth potential in the natural gas liquids-rich portion of the Marcellus Shale. (See Results of Operations – Segments, Williams Partners.)

Dividends

In July 2012, our Board of Directors approved a regular quarterly dividend of $0.3125 per share. We expect total 2012 dividends to be $1.20 per share, which is 55 percent higher than 2011, and a 20 percent dividend increase in both 2013 and 2014.

Overview of Six Months Ended June 30, 2012

Income (loss) from continuing operations attributable to The Williams Companies, Inc., for the six months ended June 30, 2012, changed unfavorably by $51 million compared to the six months ended June 30, 2011. This change reflects:

• The absence of a $124 million net 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 $77 million unfavorable change in operating income at Williams Partners primarily due to lower NGL marketing and production margins that were significantly impacted by a sharp decline in NGL prices during the second quarter of 2012. (see Results of Operations – Segments, Williams Partners);

27

Management’s Discussion and Analysis (Continued)

• A $27 million improvement in operating income at Midstream Canada & Olefins primarily due to higher olefin production margins (see Results of Operations – Segments, Midstream Canada & Olefins).

• A favorable change in investing income – net of $46 million primarily reflecting the first quarter 2012 receipt of the remaining payments on the outstanding balances due from the 2010 sale of our interest in Accroven SRL.

• Interest accrued changed favorably by $30 million primarily due to corporate debt retirements in December 2011.

• A favorable change in net income attributable to noncontrolling interests of $28 million primarily reflects lower operating results at Williams Partners.

See additional discussion in Results of Operations.

Our net cash provided by operating activities for the six months ended June 30, 2012, decreased $826 million compared to the six months ended June 30, 2011, largely due to the absence of operating cash flows from our former exploration and production business and net unfavorable changes in working capital and lower operating income.

Recent Events

• In February 2012, we announced a new interstate gas pipeline project. The new 120-mile Constitution Pipeline will connect Williams Partners’ gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. We currently own 75 percent of Constitution Pipeline. This project, along with the newly acquired Laser Gathering System and our Springville pipeline are key steps in Williams Partners’ strategy to create the Susquehanna Supply Hub, a major natural gas supply hub in northeastern Pennsylvania. In April 2012, we began the Federal Energy Regulatory Commission (FERC) pre-filing process for this project and expect to file a FERC application in January 2013.

• In March 2012, a settlement agreement was reached under which our majority-owned entities that owned and operated the El Furrial and PIGAP II gas compression facilities in Venezuela sold the assets of these facilities following their expropriation by the Venezuelan government in 2009. In connection with the settlement, we received $98 million of cash and the right to receive quarterly installments of $15 million through the first quarter of 2016. In June 2012, we received the first quarterly installment payment. Also as part of this settlement, we received $63 million in cash in March 2012 related to a previous agreement to sell our interest in Accroven SRL. (See Notes 3 and 4 of Notes to Consolidated Financial Statements.)

• In April 2012, we issued 30 million shares of common stock in a public offering at a price of $30.59 per share. We used the net proceeds of $887 million to fund a portion of the purchase of additional WPZ common units in connection with WPZ’s Caiman Acquisition.

• In April 2012, WPZ completed an equity issuance of 10 million common units representing limited partner interests at a price of $54.56 per unit. Subsequently, WPZ sold an additional 973,368 common units for $54.56 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds were used for general partnership purposes, including funding a portion of the cash purchase price of WPZ’s Caiman Acquisition.

• In July 2012, Transcontinental Gas Pipe Line Company, LLC (Transco) issued $400 million of 4.45 percent senior unsecured notes due 2042 to investors in a private debt placement. A portion of these proceeds was used to repay Transco’s $325 million 8.875 percent senior unsecured notes that matured on July 15, 2012.

• In July 2012, WPZ announced a new project to develop large-scale natural gas gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and northwest Pennsylvania. The parties anticipate investing approximately $800 million in potential development over the next several years, of which WPZ expects to fund approximately $380 million.

28

Management’s Discussion and Analysis (Continued)

• Following the spin-off of WPX Energy, Inc. (WPX) at the end of 2011 and in consideration of the growth plans of our Williams Partners and Midstream Canada & Olefins segments, we have initiated an effort to better align resources to support our business strategy in 2012 and beyond. This initiative is designed to enhance capabilities and determine the right organization – throughout the business areas and shared-services functions – to execute that strategy. We have engaged a consulting firm to assist with this project and expect to implement changes later this year through early 2013. It is likely that the recommendations arising from this effort will result in changes in our current organizational structure that will impact how our underlying businesses are managed.

• In July 2012, WPZ announced its intent to pursue an agreement to acquire our 83.3 percent interest and operatorship of an olefins-production facility located in Geismar, Louisiana from Midstream Canada & Olefins. WPZ expects to fund the transaction largely with the issuance of limited-partner units to us. The transaction is subject to execution of an agreement, review and recommendation by the conflicts committee of the general partner of WPZ, and approval of both our and WPZ’s board of directors.

Company Outlook

As previously discussed, NGL margins declined sharply during the second quarter of 2012, largely attributable to a record-warm winter, a slowing global economy, and growing NGL supplies. We expect NGL margins to remain depressed in the near-term, with some anticipated recovery by the end of the year. However, economic and commodity price indicators can be volatile and it is reasonably possible that the global economy could worsen and/or energy commodity margins could further decline, negatively impacting our future operating results. Over the next few years, we expect the influence of NGL margins on our operating results to diminish as we transition to an overall business mix that is increasingly fee-based.

Our business plan for the remainder of 2012 continues to reflect both dividend growth, as previously mentioned, and significant capital investment. Our planned capital investments total approximately $6.66 billion, including WPZ equity issued in association with the previously discussed acquisitions. We expect to fund these activities primarily through cash on hand, cash flow from operations, and debt and equity issuances by WPZ. Our structure is designed to drive lower capital costs, enhance reliable access to capital markets, and create a greater ability to pursue development projects and acquisitions. We expect to realize our growth opportunities through these continued investments in our businesses in a way that meets customer needs and enhances our competitive position by:

• Continuing to invest in and grow our midstream businesses and interstate natural gas pipeline systems;

• 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:

• General economic, financial markets, or industry downturn;

• Lower than anticipated energy commodity margins;

• Availability of capital;

• Lower than expected levels of cash flow from operations;

• Counterparty credit and performance risk;

• Decreased volumes from third parties served by our midstream businesses;

• Changes in the political and regulatory environments;

• Physical damages to facilities, especially damage to offshore facilities by named windstorms.

29

Management’s Discussion and Analysis (Continued)

We continue to address these risks through disciplined investment strategies, commodity hedging strategies, and maintaining at least $1 billion in consolidated liquidity from cash and cash equivalents and unused revolving credit facilities.

Critical Accounting Estimate

WPZ completed the Laser Acquisition in February 2012 and the Caiman Acquisition in April 2012. Based on the preliminary fair value measurements, our June 30, 2012, Consolidated Balance Sheet includes $724 million of goodwill related to these acquisitions. (See Note 2 of Notes to Consolidated Financial Statements.) We are currently evaluating the appropriate reporting unit for the allocation of the goodwill within the Williams Partners segment. We are required to evaluate the goodwill for impairment annually or more frequently if impairment indicators are present. Our evaluation will include a qualitative assessment of events or circumstances to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount. If so, we will further compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss will be recognized in the amount of the excess.

30

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 and six months ended June 30, 2012, compared to the three and six months ended June 30, 2011. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

	Three months ended June  30,											Six months ended June 30,
	2012			2011			$ Change*		% Change*			2012			2011			$ Change*		% Change*
	(Millions)											(Millions)
Revenues	$	1,846		$	1,984			-138		-7	%	$	3,865		$	3,855			+10		—
Costs and expenses:
Costs and operating expenses		1,350			1,398			+48		+3	%		2,701			2,709			+8		—
Selling, general, and administrative expenses		105			78			-27		-35	%		198			158			-40		-25	%
Other (income) expense – net		9			3			-6		-200	%		17			(3	)		-20		NM
General corporate expenses		50			45			-5		-11	%		90			92			+2		+2	%
Total costs and expenses		1,514			1,524								3,006			2,956
Operating income (loss)		332			460								859			899
Interest accrued – net		(128	)		(150	)		+22		+15	%		(259	)		(301	)		+42		+14	%
Investing income – net		30			40			-10		-25	%		130			84			+46		+55	%
Other income (expense) – net		3			(2	)		+5		NM			(1	)		4			-5		NM
Income (loss) from continuing operations before income taxes		237			348								729			686
Provision (benefit) for income taxes		71			109			+38		+35	%		204			87			-117		-134	%
Income (loss) from continuing operations		166			239								525			599
Income (loss) from discontinued operations		(1	)		58			-59		NM			135			82			+53		+65	%
Net income (loss)		165			297								660			681
Less: Net income attributable to noncontrolling interests		33			70			+37		+53	%		105			133			+28		+21	%
Net income (loss) attributable to The Williams Companies, Inc.	$	132		$	227							$	555		$	548

* + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to change in signs, a zero-value denominator, or a percentage change greater than 200.

Three months ended June 30, 2012 vs. three months ended June 30, 2011

The decrease in revenues is primarily due to lower natural gas liquid (NGL) production revenues at Williams Partners reflecting an overall significant decrease in average NGL per-unit sales prices in the second quarter of 2012. In addition, olefins and NGL production revenues as well as marketing revenues at Midstream Canada & Olefins decreased primarily due to lower average per-unit sales prices. These decreases are partially offset by higher fee revenues at Williams Partners primarily due to higher gathering, processing and transportation fees.

The decrease in costs and operating expenses is primarily due to decreased costs associated with the production of NGLs at Williams Partners reflecting lower average natural gas prices. Additionally, costs associated with the production of olefins and NGLs as well as marketing purchases at Midstream Canada & Olefins decreased primarily due to general decreases in energy commodity prices. These decreases are partially offset by Williams Partners’ increased marketing purchases and its higher operating costs primarily resulting from its acquisition transactions in 2012 and increased maintenance expenses.

31

Management’s Discussion and Analysis (Continued)

The increase in selling, general, and administrative expenses (SG&A) is primarily due to an increase at Williams Partners reflecting acquisition and transition-related costs and higher information technology and employee-related expenses driven by general growth within Williams Partners’ business operations.

The unfavorable change in operating income (loss) generally reflects decreased NGL production margins due to unfavorable energy commodity price changes in 2012 as compared to 2011, a decrease in margins related to the marketing of NGLs and higher SG&A and operating costs, partially offset by increased fee revenues as previously discussed.

Interest accrued – net changed favorably primarily due to corporate debt retirements in December 2011 and an increase in interest capitalized primarily at Midstream Canada & Olefins associated with construction projects.

The unfavorable change in investing income – net includes a $9 million decrease in equity earnings at Williams Partners primarily due to lower operating results of certain equity investees.

Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income in 2012. See Note 5 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.

See Note 3 of Notes to Consolidated Financial Statements for a discussion for the items in income (loss) from discontinued operations.

The favorable change in net income attributable to noncontrolling interests primarily reflects lower operating results at WPZ and higher income allocated to the general partner driven by incentive distribution rights, partially offset by our decreased percentage of limited partner ownership of WPZ, which was 66 percent at June 30, 2012, compared to 73 percent at June 30, 2011.

Six months ended June 30, 2012 vs. six months ended June 30, 2011

The increase in revenues is primarily due to Williams Partners’ higher fee revenues resulting from increased gathering, processing and transportation fees as well as its increased marketing revenues primarily due to higher volumes, partially offset by lower average NGL prices primarily in the second quarter of 2012. Partially offsetting these increases are lower NGL production revenues at Williams Partners reflecting an overall decrease in average NGL per-unit sales prices driven by a sharp decline in the second quarter of 2012 as well as decreases in marketing revenues and NGL and ethylene production revenues at Midstream Canada & Olefins primarily due to lower average per-unit sales prices.

The decrease in costs and operating expenses is primarily due to decreased costs associated with the production of NGLs at Williams Partners reflecting lower average natural gas prices as well as lower costs associated with the production of ethylene and NGLs and decreased marketing purchases at Midstream Canada & Olefins primarily due to general decreases in energy commodity prices. These decreases are partially offset by Williams Partners’ increased marketing purchases resulting from higher volumes, partially offset by lower average NGL prices, and its higher operating costs primarily resulting from its acquisition transactions in 2012 and increased maintenance expenses.

The increase in SG&A is primarily due to an increase at Williams Partners reflecting acquisition and transition-related costs and higher information technology and employee-related expenses driven by general growth within Williams Partners’ business operations.

The unfavorable change in other (income) expense – net within operating income is primarily due to a $13 million increase in project feasibility costs and the absence of a $10 million reversal of project feasibility costs from expense to capital in 2011 at Williams Partners. These unfavorable changes are partially offset by an $8 million favorable change in foreign exchange gains and losses at Midstream Canada & Olefins.

The unfavorable change in operating income (loss) generally reflects a decrease in margins related to the marketing of NGLs, decreased NGL production margins due to unfavorable energy commodity price changes in the second quarter of 2012 as compared to 2011, and higher SG&A and operating costs, partially offset by increased fee revenues and higher olefins margins.

32

Management’s Discussion and Analysis (Continued)

Interest accrued – net changed favorably primarily due to corporate debt retirements in December 2011 and an increase in interest capitalized primarily at Midstream Canada & Olefins associated with construction projects.

The favorable change in investing income – net is primarily due to $63 million of income recognized in 2012 as compared to an $11 million gain in 2011 at Other related to the 2010 sale of our interest in Accroven SRL. (See Note 4 of Notes to Consolidated Financial Statements.) Partially offsetting this favorable change is a $16 million decrease in equity earnings primarily resulting from lower operating results of certain equity investees at Williams Partners.

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income in 2012 and the absence of approximately $124 million tax benefit from federal settlements and an international revised assessment in 2011. See Note 5 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.

Income (loss) from discontinued operations in 2012 primarily includes a gain on reconsolidation following the sale of certain of our former Venezuela operations. See Note 3 of Notes to Consolidated Financial Statements for a discussion for the items in income (loss) from discontinued operations.

The favorable change in net income attributable to noncontrolling interests primarily reflects lower operating results at WPZ and higher income allocated to the general partner driven by incentive distribution rights, partially offset by our decreased percentage of limited partner ownership of WPZ, which was 66 percent at June 30, 2012, compared to 73 percent at June 30, 2011.

33

Management’s Discussion and Analysis (Continued)

Results of Operations — Segments

Williams Partners

Our Williams Partners segment includes WPZ, our consolidated master limited partnership, which includes two interstate natural gas pipelines, as well as investments in natural gas pipeline-related companies, which serve regions from the San Juan basin in northwestern New Mexico and southwestern Colorado to Oregon and Washington and from the Gulf of Mexico to the northeastern United States. WPZ also includes natural gas gathering, processing and treating facilities and oil gathering and transportation facilities located primarily in the Rocky Mountain, Gulf Coast, and Marcellus Shale regions of the United States. As of June 30, 2012, we own approximately 68 percent of the interests in WPZ, including the interests of the general partner, which is wholly owned by us, and incentive distribution rights.

Williams Partners’ ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission and midstream infrastructures where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers and utilizing our low cost-of-capital to invest in growing markets, including the deepwater Gulf of Mexico, the Marcellus Shale, the western United States, and areas of increasing natural gas demand.

Williams Partners’ interstate transmission and related storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion, or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have little near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

Overview of Six Months Ended June 30, 2012

Significant events during 2012 include the following:

Caiman Acquisition

In April 2012, we completed the Caiman Acquisition for consideration valued at approximately $2.3 billion. The transition of operations is under way.

The acquisition will provide us with a significant footprint and growth potential in the natural gas liquids-rich Ohio River Valley area of the Marcellus Shale. The existing physical assets acquired include a gathering system, two processing facilities, and a fractionator located in northern West Virginia and establish our new Ohio Valley Midstream business. In addition to the acquisition cost, we are committing a large portion of our planned 2012 capital expenditures for expansions to the gathering system, processing facilities, and fractionator, which are currently under construction. NGL pipelines are also planned. The assets are anchored by long-term contracted commitments, including 236,000 dedicated gathering acres from 10 producers in West Virginia, Ohio, and Pennsylvania.

The Fort Beeler plant complex has 320 million cubic feet per day (MMcf/d) of cryogenic processing capacity currently available with another 200 MMcf/d expected to be in service at the end of 2012. The Moundsville fractionator is expected to be in service by the end of the year with approximately 13 thousand barrels per day (Mbbls/d) of NGL handling capacity. An NGL pipeline, connecting the Fort Beeler plant to the Moundsville fractionator, is in the final stages of completion.

Utica Shale Infrastructure Project

We completed an agreement with Caiman Energy, LLC and others to develop midstream infrastructure serving oil and natural gas producers in the Utica Shale, primarily in Ohio and northwest Pennsylvania. The parties anticipate investing approximately $800 million, over the next several years, to develop natural gas gathering and processing and the associated liquids infrastructure, of which WPZ’s share is expected to be approximately $380 million.

34

Management’s Discussion and Analysis (Continued)

Susquehanna Supply Hub, northeastern Pennsylvania

In April 2012, we began the FERC pre-filing process for a new interstate gas pipeline project. We currently own a 75 percent interest in the project and will be the operator. The new 120-mile Constitution Pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. The total cost of the project is estimated to be $748 million. We plan to place the project into service in March 2015, with an expected capacity of 650 thousand dekatherms per day (Mdth/d). The pipeline is fully subscribed with two shippers. We expect to file a FERC application in January 2013.

In February 2012, we completed the Laser Acquisition for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments and 7,531,381 of WPZ’s common units valued at $441 million. The gathering system is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in Susquehanna County, Pennsylvania, as well as 10 miles of gathering pipeline in southern New York. The acquisition is supported by existing long-term gathering agreements that provide acreage dedications and volume commitments.

Our Springville pipeline was placed into service in January 2012, allowing us to deliver approximately 300 MMcf/d into the Transco pipeline. This new take-away capacity allows full use of approximately 650 MMcf/d of capacity from various compression and dehydration expansion projects to our gathering business in northeastern Pennsylvania’s Marcellus Shale which we acquired at the end of 2010. In conjunction with a long-term agreement with a significant producer, we are operating the 33-mile, 24-inch diameter natural gas gathering pipeline, connecting a portion of our gathering assets into the Transco pipeline. Expansions to the Springville compression facilities in 2012 are expected to increase the capacity to approximately 625 MMcf/d.

As production in the Marcellus increases and expansion projects are completed, the Susquehanna Supply Hub is expected to reach a natural gas take away capacity of 3 billion cubic feet per day (Bcf/d) by 2015, including capacity contributions from the Constitution Pipeline.

Volatile commodity prices

Average per-unit NGL margins declined sharply in the second quarter of 2012 and were approximately 7 percent lower in the first half of 2012 than in the same period of 2011. Key factors in the NGL market weakness have been high propane inventories caused by the extremely warm winter and the effect of the propane oversupply on ethane inventories and pricing. Lower natural gas prices driven by abundant natural gas supplies partially offset the weaker NGL prices.

NGL margins are defined as NGL revenues less any applicable British thermal unit (BTU) replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.

35

Management’s Discussion and Analysis (Continued)

Outlook for the Remainder of 2012

Commodity price changes

• We expect our average per-unit NGL margins to be slightly lower than the second quarter of 2012 with some recovery later in the year, with the full year 2012 lower than 2011 and comparable to our rolling five-year average per-unit NGL margins. NGL price changes have historically tracked somewhat with changes in the price of crude oil, although NGL, crude, and natural gas prices are highly volatile, difficult to predict, and are often not highly correlated. NGL margins are highly dependent upon continued demand within the global economy. However, NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets.

• As part of our efforts to manage commodity price risks on an enterprise basis, we continue to evaluate our commodity hedging strategies. To reduce the exposure to changes in market prices, we have entered into NGL swap agreements to fix the prices of approximately 11 percent to 14 percent of our anticipated NGL sales volumes and an approximate corresponding portion of anticipated shrink natural gas requirements for the remainder of 2012. The combined impact of these energy commodity derivatives, designated as cash flow hedges will provide a margin on the hedged volumes of $122 million.

Gathering, processing, and NGL sales volumes

• The growth of natural gas supplies supporting our gathering and processing volumes are impacted by producer drilling activities, which are influenced by natural gas prices.

• In Williams Partners onshore businesses, we anticipate significant growth in our natural gas gathering volumes as our infrastructure grows to support drilling activities in our Ohio Valley Midstream and Susquehanna

36

Management’s Discussion and Analysis (Continued)

Supply Hub businesses in the Marcellus Shale region. We anticipate equity NGL volumes in 2012 to be comparable to 2011. Sustained low natural gas prices could discourage producer drilling activities in our onshore areas and unfavorably impact the supply of natural gas available to gather and process in the long term.

• In Williams Partners gulf coast businesses, we expect higher gas gathering, processing, and crude transportation volumes compared to the latter half of 2011, as production flowing through our Perdido Norte pipelines becomes consistent and other in-process drilling is completed. Increases in permitting, subsequent to the 2010 drilling moratorium, give us reason to expect gradual increased drilling activities in the Gulf of Mexico. In the Gulf Coast, our customers’ drilling activities are primarily focused on crude oil economics, rather than natural gas. We have not experienced, and do not anticipate an overall significant decline in volumes due to reduced drilling activities.

• We anticipate higher general and administrative, operating, and depreciation expense supporting our growing operations in the Marcellus Shale area, Piceance basin, and western Gulf of Mexico.

Expansion projects

We expect to invest total capital of $5.7 billion to $6.0 billion in 2012. The ongoing major expansion projects include the following:

Mid-South

In August 2011, we received approval from the FERC to upgrade compressor facilities and expand our existing natural gas transmission system from Alabama to markets as far north as North Carolina. The cost of the project is estimated to be $217 million. The project is expected to be phased into service in September 2012 and June 2013 with an expected increase in capacity of 225 Mdt/d.

Mid-Atlantic Connector

In July 2011, we received approval from the FERC to expand our existing natural gas transmission system from North Carolina to markets as far downstream as Maryland. The cost of the project is estimated to be $55 million and is expected to increase capacity by 142 Mdth/d. We plan to place the project into service in November 2012.

Northeast Supply Link

In December 2011, we filed an application with the FERC to expand our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. The cost of the project is estimated to be $341 million and is expected to increase capacity by 250 Mdth/d. We plan to place the project into service in November 2013.

Marcellus Shale Expansions

• Expansion of our Susquehanna Supply Hub in northeastern Pennsylvania, as previously discussed.

• As previously discussed, expansions currently under construction to our natural gas gathering system, processing facilities, and fractionator in our Ohio Valley Midstream business of the Marcellus Shale.

• Expansions to our gathering system through capital to be invested within our Laurel Mountain equity investment, also in the Marcellus Shale region. The Shamrock compressor station, currently providing 60 MMcf/d of capacity, is expandable to 350 MMcf/d and will likely be the largest central delivery point out of the Laurel Mountain system. Our equity investee is progressing on further expansions to the Shamrock compressor station and other additions to the gathering infrastructure in 2012.

37

Management’s Discussion and Analysis (Continued)

Gulfstar FPS™ Deepwater Project

We will design, construct, and install our Gulfstar FPS™, a spar-based floating production system that utilizes a standard design approach with a capacity of 60 Mbbls/d of oil, up to 200 MMcf/d of natural gas, and the capability to provide seawater injection services. We expect Gulfstar FPS™ to be capable of serving as a central host facility for other deepwater prospects in the area. Construction is underway and the project is expected to be in service in 2014.

Parachute

In conjunction with a basin-wide agreement for all gathering and processing services provided by us to WPX in the Piceance basin, we plan to construct a 350 MMcf/d cryogenic natural gas processing plant. The Parachute TXP I plant is expected to be in service in 2014.

Keathley Canyon Connector™

Our equity investee which we operate, Discovery Producer Services LLC (Discovery), plans to construct, own, and operate a new 215-mile, 20-inch deepwater lateral pipeline from a third-party floating production facility located in the Keathley Canyon Block in the central deepwater Gulf of Mexico. Discovery has signed long-term agreements with anchor customers for natural gas gathering and processing services for production from those fields. The Keathley Canyon Connector™ lateral will originate from a third-party floating production facility in the southeast portion of the Keathley Canyon area and will connect to Discovery’s existing 30-inch offshore natural gas transmission system. The lateral pipeline is estimated to have the capacity to flow more than 400 MMcf/d and will accommodate the tie-in of other deepwater prospects. Pre-construction activities have begun, the pipeline is expected to be laid in 2013, and is planned to be in-service in mid-2014.

Overland Pass Pipeline Expansion

Through our equity investment in Overland Pass Pipeline Company LLC, we are participating in the construction of a pipeline connection and capacity expansions, expected to be complete in early 2013, to increase the pipeline’s capacity to the maximum of 255 Mbbls/d, to accommodate new volumes coming from the Bakken Shale in the Williston basin.

Eminence Storage Field Leak

On December 28, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Mississippi. Due to the leak and related damage to the well at an adjacent cavern, both caverns are out of service. In addition, two other caverns at the field, which were constructed at or about the same time as those caverns, have experienced operating problems, and we have determined that they should also be retired. The event has not affected the performance of our obligations under our service agreements with our customers.

In September 2011, we filed an application with the FERC seeking authorization to abandon these four caverns. We estimate the total abandonment costs, which will be capital in nature, will be approximately $90 million, which is expected to be spent through the first half of 2013. As of June 30, 2012, we have incurred approximately $57 million in cumulative abandonment costs. This estimate is subject to change as work progresses and additional information becomes known. Management considers these costs to be prudent costs incurred in the abandonment of these caverns and expects to recover these costs, net of insurance proceeds, in future rate filings. To the extent available, the abandonment costs will be funded from the ARO Trust. (See Note 11 of Notes to Consolidated Financial Statements.)

Filing of Rate Cases

Pursuant to the terms of Transco’s most recent rate settlement agreement, Transco must file a new rate case no later than August 31, 2012.

38

Management’s Discussion and Analysis (Continued)

During the first quarter of 2012, Northwest Pipeline filed a Stipulation and Settlement Agreement with the FERC for an increase in their rates. Northwest Pipeline received FERC approval during the second quarter of 2012. The new rates, which as filed are 7.4 percent higher than current rates, will become effective January 1, 2013.

Period-Over-Period Operating Results

	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
	(Millions)
Segment revenues	$	1,583	$	1,671	$	3,268	$	3,250
Segment profit	$	339	$	471	$	827	$	908

Three months ended June 30, 2012 vs. three months ended June 30, 2011

The decrease in segment revenues includes:

• A $118 million decrease in revenues from our equity NGLs reflecting a decrease of $99 million associated with an overall 30 percent decrease in average NGL per-unit sales prices, driven by a sharp decline in the second quarter of 2012. Average ethane and non-ethane per-unit prices decreased by 50 percent and 18 percent, respectively.

• A $15 million decrease in system management gas sales (offset in segment costs and expenses).

• A $41 million increase in fee revenues primarily due to new volumes on our recently acquired natural gas gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses of the Marcellus Shale and higher volumes on our Perdido Norte natural gas and oil pipelines in the western deepwater Gulf of Mexico.

• An $8 million increase in natural gas transportation revenues associated with gas pipeline expansion projects placed into service in 2011.

Segment costs and expenses increased $35 million, including:

• A $36 million increase in marketing purchases primarily due to higher NGL volumes, partially offset by significantly lower average NGL prices.

• A $32 million increase in operating costs including new depreciation and maintenance costs associated with assets acquired in early 2012 and higher turbine and engine maintenance expenses, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.

• A $25 million increase in general and administrative expenses including $18 million of Caiman and Laser acquisition and transition-related costs, and increases in information technology and employee-related expenses driven by general growth within our business operations.

• An $8 million increase in project feasibility costs.

• A $54 million decrease in costs associated with our equity NGLs primarily due to a 48 percent decrease in average natural gas prices.

• A $15 million decrease in system management gas costs (offset in segment revenues).

39

Management’s Discussion and Analysis (Continued)

The decrease in segment profit includes:

• A $64 million decrease in NGL margins reflecting a $99 million decrease related to significantly lower NGL prices, partially offset by a $49 million decrease in shrink costs due to significantly lower natural gas prices.

• A $32 million increase in operating costs as previously discussed.

• A $32 million decrease in margins related to the marketing of NGLs, primarily due to the impact of a significant and rapid decline in NGL prices while product was in transit during the second quarter of 2012 compared to periods of increasing prices during the second quarter of 2011.

• A $25 million increase in general and administrative expenses as previously discussed.

• A $9 million decrease in equity earnings primarily due to $7 million lower Laurel Mountain equity earnings driven by higher operating costs including depreciation and lower gathering rates indexed to natural gas prices, partially offset by higher gathered volumes. In addition, Discovery had $5 million lower equity earnings primarily due to lower NGL margins.

• An $8 million increase in project feasibility costs.

• A $41 million increase in fee revenues as previously discussed.

Six months ended June 30, 2012 vs. six months ended June 30, 2011

The increase in segment revenues includes:

• An $82 million increase in fee revenues primarily due to new volumes on our recently acquired gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses of the Marcellus Shale and higher volumes on our Perdido Norte natural gas and oil pipelines in the western deepwater Gulf of Mexico. In addition, gathering volumes are higher in our onshore assets in the West due primarily to the absence of severe winter weather conditions in the first quarter of 2011 which limited producers’ ability to deliver natural gas and higher volumes in the Piceance basin.

• A $53 million increase in marketing revenues primarily due to higher NGL volumes, partially offset by lower average NGL prices, primarily in the second quarter of 2012. The changes in NGL marketing revenues are more than offset by similar changes in NGL marketing purchases.

• A $26 million increase in natural gas transportation revenues associated with gas pipeline expansion projects placed into service in 2011.

• A $111 million decrease in revenues from our equity NGLs reflecting a decrease of $105 million associated with an overall 18 percent decrease in average NGL per-unit sales prices, driven by a sharp decline in the second quarter of 2012. Average ethane and non-ethane per-unit prices decreased by 32 percent and 8 percent, respectively.

• A $28 million decrease in system management gas sales (offset in segment costs and expenses).

Segment costs and expenses increased $95 million, including:

• A $103 million increase in marketing purchases primarily due to higher NGL volumes, partially offset by lower average NGL prices.

• A $39 million increase in general and administrative expenses including $19 million of Caiman and Laser acquisition and transition-related costs, and increases in information technology and employee-related expenses driven by general growth within our business operations.

40

Management’s Discussion and Analysis (Continued)

• A $30 million increase in operating costs including new depreciation and maintenance costs associated with assets acquired in early 2012 and higher turbine and engine maintenance costs, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.

• A $30 million unfavorable change primarily due to a $13 million increase in project feasibility costs and the absence of a $10 million first-quarter 2011 reversal of project feasibility costs from expense to capital.

• An $82 million decrease in costs associated with our equity NGLs primarily due to a 37 percent decrease in average natural gas prices.

• A $28 million decrease in system management gas costs (offset in segment revenues).

The decrease in segment profit reflects the previously described changes in segment revenues and segment costs and expenses. A more detailed analysis of segment profit is presented as follows.

The decrease in segment profit includes:

• A $50 million decrease in margins related to the marketing of NGLs, primarily due to the impact of a significant and rapid decline in NGL prices during the second quarter of 2012 while product was in transit compared to periods of increasing prices during 2011.

• A $39 million increase in general and administrative expenses as previously discussed.

• A $30 million increase in operating costs as previously discussed.

• A $30 million unfavorable change primarily due to a $13 million increase in project feasibility costs and the absence of a $10 million first-quarter 2011 reversal of project feasibility costs from expense to capital.

• A $29 million decrease in NGL margins driven primarily by commodity price changes including a $105 million decrease related to lower NGL prices, partially offset by a $73 million increase related to lower natural gas prices.

• A $4 million decrease in equity earnings primarily due to lower equity earnings of $10 million for Laurel Mountain, $3 million for Aux Sable, and $3 million for Discovery, partially offset by higher equity earnings of $9 million due to the acquisition of an additional 24.5 percent in Gulfstream in May 2011. The decrease in Laurel Mountain is driven by higher operating costs including depreciation and lower gathering rates indexed to natural gas prices, partially offset by higher gathered volumes.

• An $82 million increase in fee revenues as previously discussed.

• A $26 million increase in natural gas transportation revenues as previously discussed.

Midstream Canada & Olefins

Our Midstream Canada & Olefins segment includes our oil sands offgas processing plant near Fort McMurray, Alberta, our NGL/olefin fractionation facility at Redwater, Alberta, our NGL light-feed olefins cracker in Geismar, Louisiana along with associated ethane and propane pipelines, and our refinery grade propylene splitter in Louisiana. The products we produce are: NGLs, ethylene, propylene, and other co-products. Our NGL products include: propane, normal butane, isobutane/butylene (butylene), and condensate.

Overview of Six Months Ended June 30, 2012

Boreal Pipeline

The Boreal Pipeline was completed and placed in service mid-June 2012. The Boreal Pipeline is a 261-mile, 12-inch diameter pipeline in Canada that transports recovered NGLs and olefins from our extraction plant in Fort McMurray to our Redwater fractionation facility. The pipeline has an initial capacity of 43 Mbbls/d that can be increased to an ultimate capacity of 125 Mbbls/d with additional pump stations. The ultimate capacity provides sufficient capacity to transport additional recovered liquids in excess of those from our current agreements. Filling the pipeline with product reduced the volumes available for sale in June 2012.

41

Management’s Discussion and Analysis (Continued)

Outlook for the Remainder of 2012

Volatile commodity prices

While per-unit margins are volatile and highly dependent upon continued demand within the global economy, we believe that our average per-unit ethylene margin will increase over 2011 levels. We expect ethylene margins to benefit from lower ethane prices. However, we experienced a 24 percent decline in our average per-unit Canadian NGL margins from first-quarter 2012 to second-quarter 2012. We expect that our total year 2012 average per-unit Canadian propylene and NGL margins will decline from our robust 2011 per-unit margins resulting from projected lower per-unit propylene and NGL sales pricing. NGL products are currently the preferred feedstock for ethylene and propylene production which has been shifting away from the more expensive crude-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets because of our NGL-based olefins production.

Volume impacts

We expect our 2012 production sales volumes to be comparable or increase over 2011 levels.

Allocation of capital to projects

We expect to spend $675 million to $775 million in 2012 on capital projects. The major expansion projects include:

• An expansion of our Geismar olefins production facility which is expected to increase the facility’s ethylene production capacity by 600 million pounds per year to a new annual capacity of 1.95 billion pounds. We are currently in the detailed engineering and procurement phase and are beginning the construction phase. We expect to complete the expansion in the latter part of 2013.

• The ethane recovery project, which is an expansion of our Canadian facilities that will allow us to recover ethane/ethylene mix from our operations that process offgas from the Alberta oil sands. We plan to modify our oil sands offgas extraction plant near Fort McMurray, Alberta, and construct a de-ethanizer at our Redwater fractionation facility. Our de-ethanizer is expected to initially process approximately 10,000 bbls/d of ethane/ethylene mix. We have signed a long-term contract to provide the ethane/ethylene mix to a third-party customer. We have begun construction and we expect to complete the expansions and begin producing ethane/ethylene mix in mid-year 2013.

Period-Over-Period Operating Results

	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
	(Millions)
Segment revenues	$	271	$	347	$	616	$	663
Segment profit	$	68	$	72	$	171	$	146

Three months ended June 30, 2012 vs. three months ended June 30, 2011

  Segment revenues decreased primarily due to:

• $25 million lower ethylene product sales revenues due to 19 percent lower average per-unit sales prices and slightly lower sales volumes. The lower average per-unit sales prices resulted from general decreases in commodity pricing.

42

Management’s Discussion and Analysis (Continued)

• $23 million lower marketing revenues due to general decreases in energy commodity prices on lower volumes. The lower marketing revenues were substantially offset by similar changes in marketing purchases described below.

• $22 million lower NGL product sales revenues due to 30 percent lower average per-unit sales prices and 8 percent lower sales volumes. The lower average per-unit sales prices resulted from general decreases in commodity pricing. The lower sales volumes primarily resulted from the impact of filling the Boreal pipeline and the absence of 2011 processing of Canadian butane/butylene product in storage, partially offset by improved Canadian production in 2012 and the absence of 2011 supply constraints at our Louisiana refinery grade splitter.

• $10 million lower propylene product sales revenues due to 25 percent lower average per-unit sales prices, partially offset by 19 percent higher volumes. The lower average per-unit sales prices resulted from general decreases in commodity pricing. The higher volumes resulted from the absence of 2011 supply constraints at our Louisiana refinery grade splitter and improved Canadian production in 2012, partially offset by the impact of filling the Boreal pipeline.

  Segment costs and expenses decreased $72 million primarily due to:

• $37 million lower ethylene feedstock costs resulting from 42 percent lower average per-unit feedstock costs, and slightly lower sales volumes. The lower average per-unit feedstock costs resulted from general decreases in commodity pricing.

• $22 million decreased marketing purchases due to general decreases in energy commodity prices on lower volumes. The decreased marketing purchases substantially offset similar changes in marketing revenues.

• $7 million lower NGL feedstock costs resulting from 19 percent lower average per-unit feedstock costs and lower sales volumes.

• $5 million lower propylene feedstock costs resulting from 22 percent lower average per-unit feedstock costs, partially offset by 19 percent higher sales volumes.

Segment profit decreased primarily due to $15 million lower Canadian NGL product margins resulting from 19 percent lower sales volumes and 31 percent lower average per-unit margins, combined with $5 million lower propylene margins from 32 percent lower average per-unit margins on higher sales volumes. This decrease was substantially offset by $12 million higher Geismar ethylene product margins due primarily to 35 percent higher per-unit margins.

Six months ended June 30, 2012 vs. six months ended June 30, 2011

  Segment revenues decreased primarily due to:

• $30 million lower marketing revenues due to general second quarter of 2012 decreases in energy commodity prices on lower volumes. The lower marketing revenues were substantially offset by similar changes in marketing purchases described below.

• $20 million lower NGL product sales revenues primarily due to 15 percent lower average per-unit sales prices.

• $7 million lower ethylene product sales revenues primarily due to 4 percent lower average per-unit sales prices, partially offset by 2 percent higher volumes.

These decreases are partially offset by $8 million higher butadiene and debutanized aromatic concentrate (DAC) product sales revenues due to higher per-unit prices and higher volumes.

43

Management’s Discussion and Analysis (Continued)

  Segment costs and expenses decreased $72 million primarily due to:

• $37 million lower ethylene feedstock costs resulting from 24 percent lower average per-unit feedstock costs, slightly offset by 2 percent higher volumes.

• $29 million decreased marketing purchases due to general decreases in energy commodity prices on lower volumes. The decreased marketing purchases substantially offset similar changes in marketing revenues.

• $10 million lower NGL feedstock costs resulting from 16 percent lower average per-unit feedstock costs.

• $8 million favorable change in foreign exchange gains and losses related to the revaluation of current assets held in U.S. dollars within our Canadian operations.

These decreases were partially offset by $10 million increased operating and maintenance costs resulting from higher costs in our Canadian operations and domestic olefins operations.

  Segment profit increased primarily due to:

• $30 million higher Geismar ethylene product sales margins resulting primarily from 41 percent higher average per-unit margins.

• $9 million higher Geismar butadiene and DAC product sales margins resulting from higher per-unit margins and increased volumes.

• $8 million favorable change in foreign exchange gains and losses.

These increases were partially offset by $10 million higher overall operating and maintenance costs and $10 million lower Canadian NGL product margins primarily due to lower per-unit margins.

Other

Other includes other business activities that are not operating segments as well as corporate operations.

Period-Over-Period Operating Results

	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
	(Millions)
Segment revenues	$	7	$	7	$	13	$	13
Segment profit	$	1	$	2	$	60	$	22

Six months ended June 30, 2012 vs. six months ended June 30, 2011

The increase in segment profit is primarily due to gains related to the 2010 sale of our interest in Accroven SRL of $53 million in 2012 compared to $11 million in 2011. As part of a settlement regarding certain Venezuelan assets in the first quarter of 2012, we received payment for all outstanding balances due from this sale. (See Note 4 of Notes to Consolidated Financial Statements.)

44

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

The sharp decline in NGL margins during the second quarter of 2012 and our related expectation of depressed near-term NGL margins has reduced the expected level of operating cash flows from certain of our businesses in 2012. However, we note that further reduction in expected energy commodity prices would be somewhat mitigated by certain of our cash flow streams that are substantially insulated from short-term changes in commodity prices as follows:

• Firm demand and capacity reservation transportation revenues under long-term contracts from our gas pipelines;

• Fee-based revenues from certain gathering and processing services in our midstream businesses.

Over the longer-term, we expect the influence of short-term changes in commodity prices on our cash flows to diminish as we transition to an overall business mix that is increasingly fee-based.

We continue to believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for capital and investment expenditures, dividends and distributions, working capital, and tax and debt payments while maintaining a sufficient level of liquidity. In particular, we note the following for 2012:

• We expect capital investments to total between $5.275 billion and $5.675 billion in 2012, excluding WPZ equity issued in association with the Laser and Caiman Acquisitions of approximately $1 billion. Of this total, maintenance capital expenditures, which are generally considered nondiscretionary and include expenditures to meet legal and regulatory requirements, to maintain and/or extend the operating capacity and useful lives of our assets, and to complete certain well connections, are expected to total between $480 million and $560 million. Expansion capital, which is generally more discretionary to fund projects in order to grow our business, is expected to total between $4.795 billion and $5.115 billion. See Results of Operations – Segments, Williams Partners and Midstream Canada & Olefins for discussions describing the general nature of these investments.

• We expect to pay total cash dividends of approximately $1.20 per common share, an increase of almost 55 percent over 2011 levels. We expect to increase our dividend quarterly through paying out substantially all of the cash distributions, net of applicable taxes, interest and costs, we receive from WPZ.

• We expect to fund capital and investment expenditures, tax and debt payments, dividends and distributions, and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, utilization of our revolving credit facilities, and proceeds from debt issuances and sales of WPZ debt and equity securities as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $1.75 billion and $2 billion in 2012.

• We expect to maintain consolidated liquidity (which includes liquidity at WPZ) of at least $1 billion from cash and cash equivalents and unused revolving credit facilities.

• In July 2012, Transco received net proceeds of $395 million from the issuance of $400 million of 4.45 percent senior unsecured notes due in 2042. The expected use of proceeds included repayment of Transco’s $325 million 8.875 percent notes upon their maturity on July 15, 2012, and general corporate purposes, including capital expenditures.

Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include:

• Sustained reductions in energy commodity prices from the range of current expectations;

• Lower than expected distributions, including IDRs, from WPZ. WPZ’s liquidity could also be impacted by a lack of adequate access to capital markets to fund its growth;

• Lower than expected levels of cash flow from operations from Midstream Canada & Olefins.

45

Management’s Discussion and Analysis (Continued)

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2012. Our internal and external sources of consolidated liquidity include cash generated from our operations, cash and cash equivalents on hand, and our credit facilities. Additional sources of liquidity, if needed, include bank financings, proceeds from the issuance of long-term debt and equity securities, and proceeds from asset sales. These sources are available to us at the parent-company level and are expected to be available to certain of our subsidiaries, particularly equity and debt issuances from WPZ. WPZ is expected to be self-funding through its cash flows from operations, use of its credit facility, and its access to capital markets. WPZ makes cash distributions to us in accordance with the partnership agreement, which considers our level of ownership and incentive distribution rights. Our ability to raise funds in the capital markets will be impacted by our financial condition, interest rates, market conditions, and industry conditions.

			June 30, 2012
Available Liquidity	Expiration		WPZ		WMB			Total
			(Millions)
Cash and cash equivalents			$	34	$	645	(1)	$	679
Capacity available under our $900 million senior unsecured revolving credit facility (2)		June 3, 2016				900			900
Capacity available to WPZ under its $2 billion senior unsecured revolving credit facility (3)		June 3, 2016		1,655					1,655
			$	1,689	$	1,545		$	3,234

(1) Includes $578 million of cash and cash equivalents that is being held by certain subsidiary and international operations and is not considered available for general corporate purposes. The remainder of our cash and cash equivalents is primarily held in government-backed instruments.

(2) At June 30, 2012, we are in compliance with the financial covenants associated with this credit facility agreement.

(3) At June 30, 2012, WPZ is in compliance with the financial covenants associated with this credit facility agreement. This credit facility is only available to WPZ, Transco and Northwest Pipeline as co-borrowers.

In addition to the credit facilities listed above, we have issued letters of credit totaling $24 million as of June 30, 2012 under certain bilateral bank agreements.

Shelf Registrations

WPZ filed a shelf registration statement as a well-known, seasoned issuer in February 2012 that allows it to issue an unlimited amount of registered debt and limited partnership unit securities.

At the parent-company level, we filed a shelf registration statement as a well-known, seasoned issuer in May 2012 that allows us to issue an unlimited amount of registered debt and equity securities.

Equity Offerings

In April 2012, we issued 30 million shares of common stock in a public offering at a price of $30.59 per share. We used the net proceeds of $887 million to fund a portion of the purchase of additional WPZ common units in connection with WPZ’s Caiman Acquisition.

46

Management’s Discussion and Analysis (Continued)

In April 2012, WPZ completed an equity issuance of 10 million common units representing limited partner interests in them at a price of $54.56 per unit. Subsequently, WPZ sold an additional 973,368 common units for $54.56 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds of $581 million were used for general partnership purposes, including the funding of a portion of the cash purchase price of the Caiman Acquisition.

In January 2012, WPZ completed an equity issuance of 7 million common units representing limited partner interests in them at a price of $62.81 per unit. In February 2012, WPZ sold an additional 1.05 million common units for $62.81 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds of $490 million were used to fund capital expenditures and for general partnership purposes.

Acquisitions

In April 2012, WPZ completed the Caiman Acquisition in exchange for aggregate consideration of $1.72 billion in cash, net of purchase price adjustments, and 11,779,296 of WPZ’s common units. In connection with this acquisition, we made an additional investment in WPZ of $1 billion to facilitate the acquisition. We purchased 16,360,133 WPZ common units and have agreed to temporarily waive our incentive distribution rights (IDRs) related to these units and the units issued to the seller of Caiman Eastern Midstream, LLC, in connection with this acquisition. We estimate the foregone IDRs would have yielded approximately $24 million in 2012.

In February 2012, WPZ completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC in exchange for $325 million in cash, net of cash acquired in the transaction, and 7,531,381 of WPZ’s common units.

Credit Ratings

Our ability to borrow money is impacted by our credit ratings and the credit ratings of WPZ. The current ratings are as follows:

	Rating Agency	Date of Last Change	Outlook	Senior Unsecured Debt Rating	Corporate Credit Rating
Williams:
	Standard & Poor’s	March 5, 2012	Stable	BBB-	BBB
	Moody’s Investors Service	February 27, 2012	Stable	Baa3	N/A
	Fitch Ratings	February 9, 2012	Stable	BBB-	N/A
Williams Partners:
	Standard & Poor’s	March 5, 2012	Stable	BBB	BBB
	Moody’s Investors Service	February 27, 2012	Stable	Baa2	N/A
	Fitch Ratings	February 9, 2012	Positive	BBB-	N/A

With respect to Standard and Poor’s, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard and Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard and Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.

With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. The “1”, “2”, and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” indicates a ranking at the lower end of the category.

47

Management’s Discussion and Analysis (Continued)

With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.

Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A downgrade of our credit rating might increase our future cost of borrowing and would require us to post additional collateral with third parties, negatively impacting our available liquidity. As of June 30, 2012, we estimate that a downgrade to a rating below investment grade for us or WPZ could require us to post up to $35 million or $199 million, respectively, in additional collateral with third parties.

Sources (Uses) of Cash

	Six months ended June 30,
	2012			2011
	(Millions)
Net cash provided (used) by:
Operating activities	$	858		$	1,684
Financing activities		1,822			(114	)
Investing activities		(2,890	)		(1,199	)
Increase (decrease) in cash and cash equivalents	$	(210	)	$	371

Operating activities

Our net cash provided by operating activities for the six months ended June 30, 2012, decreased $826 million from the same period in 2011 largely due to the absence of cash flows from our former exploration and production business and net unfavorable changes in working capital and lower operating income.

Financing activities

Significant transactions include:

• $887 million net proceeds received from our second quarter 2012 equity offering;

• $581 million received from WPZ’s second quarter 2012 equity offering;

• $490 million received from WPZ’s first quarter 2012 equity offering;

• $500 million received from revolver borrowings on WPZ’s $2 billion unsecured credit facility for capital expenditures and general partnership purposes in second quarter 2012;

• $155 million of revolver borrowings paid during second quarter 2012;

• We paid $342 million in 2012 and $191 million in 2011 of quarterly dividends on common stock;

• We paid $190 million in 2012 and $105 million in 2011 of dividends and distributions to noncontrolling interests;

• $150 million paid to retire WPZ’s senior unsecured notes that matured in June 2011;

• $300 million received in revolver borrowings from WPZ’s previous $1.75 billion unsecured credit facility used for WPZ’s acquisition of a 24.5 percent interest in Gulfstream from us in May 2011. This obligation was transferred to WPZ’s $2 billion unsecured credit facility at its inception in June 2011.

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Management’s Discussion and Analysis (Continued)

Investing activities

Significant transactions include:

• $1.72 billion paid, net of purchase price adjustments, for WPZ’s Caiman Acquisition in April 2012;

• $325 million paid, net of cash acquired in the transaction, for WPZ’s acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC in March 2012;

• $121 million received from the reconsolidation of the Wilpro entities. (See Note 3 of our Notes to Consolidated Financial Statements.) This cash is only considered available for use in our international operations;

• Capital expenditures totaled $922 million and $1,094 million for 2012 and 2011, respectively.

Off-Balance Sheet Financing Arrangements and Guarantees of Debt or Other Commitments

We have various other guarantees and commitments which are disclosed in Notes 11 and 13 of Notes to Consolidated Financial Statements. We do not believe these guarantees or the possible fulfillment of them will prevent us from meeting our liquidity needs.

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Item 3

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first six months of 2012.

Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of natural gas and NGLs, as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts, and limited proprietary trading activities. Our management of the risks associated with these market fluctuations includes maintaining a conservative capital structure and significant liquidity, as well as using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. (See Note 12 of Notes to Consolidated Financial Statements.)

We measure the risk in our portfolio using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolio. Value-at-risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolio. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolio will not exceed the value-at-risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolio in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.

We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value-at-risk separately for these two categories. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from our estimation of value-at-risk.

Trading

Our trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. The fair value of our trading derivatives was a net asset of less than $0.1 million at June 30, 2012 and December 31, 2011. The value-at-risk for contracts held for trading purposes was zero at June 30, 2012 and less than $0.1 million at December 31, 2011.

Nontrading

Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from the following activities:

Segment	Commodity Price Risk Exposure
Williams Partners	• Natural gas purchases
	• NGL sales
Midstream Canada & Olefins	• NGL purchases and sales

50

The fair value of our nontrading derivatives was a net asset of $41 million at June 30, 2012 and a net asset of $1 million at December 31, 2011. The value-at-risk for derivative contracts held for nontrading purposes was $2 million at June 30, 2012, and zero at December 31, 2011.

Certain of the derivative contracts held for nontrading purposes are accounted for as cash flow hedges. Of the total fair value of nontrading derivatives, cash flow hedges had a net asset value of $41 million at June 30, 2012 and a net asset value of zero at December 31, 2011. Though these contracts are included in our value-at-risk calculation, any changes in the fair value of the effective portion of these hedge contracts would generally not be reflected in earnings until the associated hedged item affects earnings.

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Item 4

Controls and Procedures

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) or our internal controls over financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.

In April 2012, we identified a material weakness related to accounting for deferred income taxes related to our investment in Williams Partners L.P. (WPZ) associated with gains recorded as part of stockholders’ equity on units that WPZ issued in prior years.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

Previously, we had not recorded deferred income taxes related to our investment in WPZ associated with gains recorded as part of stockholders’ equity on units that WPZ issued in prior years. However, in accordance with ASC 740 Income Taxes, we concluded that we should recognize deferred income taxes for tax effects arising from the differences in our financial and income tax bases in our WPZ investment resulting from these transactions. During the second quarter of 2012, we corrected and refiled our financial statements for the period ended December 31, 2011, revised our accounting process associated with our investment in WPZ, corrected our method of accounting for deferred income taxes related to our investment in WPZ associated with gains recorded as part of stockholders’ equity on units that WPZ issues and utilized this corrected method of accounting in connection with second-quarter 2012 transactions related to our investment in WPZ. We also enhanced our controls for oversight of tax accounting for our financial investment in WPZ and enhanced our process and procedures related to communication between our financial reporting and income tax personnel. We consider this material weakness to be remediated as of June 30, 2012.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Second-Quarter 2012 Changes in Internal Controls

Other than described above, there have been no changes during the second quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our Internal Controls.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Environmental

Certain reportable legal proceedings involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings which are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.

In September 2007, the EPA requested, and Transco later provided, information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of Transco’s 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 a response denying the allegations in June 2008. In May 2011, Transco provided additional information to the EPA pertaining to these compressor stations in response to a request they had made in February 2011. In August 2010, the EPA requested, and Transco provided, similar information for a compressor station in Maryland.

In September 2011, the Colorado Department of Public Health and Environment issued a Notice of Violation for alleged violations of the Colorado Clean Water Act related to excavation work being done for our Crawford Trail Pipeline. In June 2012, we agreed to a settlement in principle with the agency for $275,000.

Other

The additional information called for by this item is provided in Note 13 of the Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this item.

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Item 6. Exhibits

Exhibit No.		Description
Exhibit 3.1	—	Restated Certificate of Incorporation (filed on May 26, 2010, as Exhibit 3.1 to the Company’s Current Report on Form 8-K) and incorporated herein by reference.
Exhibit 3.2	—	Restated By-Laws (filed on May 26, 2010, as Exhibit 3.2 to the Company’s Current Report on Form 8-K) and incorporated herein by reference.
Exhibit 4.1	—	Indenture, dated as of July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on July 16, 2012 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.
Exhibit 4.2	—	Registration Rights Agreement, dated July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and the initial purchasers listed therein (filed on July 16, 2012 as Exhibit 10.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.
*Exhibit 10.1	—	First Amendment to Contribution Agreement, dated as of April 27, 2012, between Caiman Energy, LLC and Williams Partners L.P.
*Exhibit 10.2	—	Form of 2012 Restricted Stock Unit Agreement among The Williams Companies, Inc. and nonmanagement directors.
*Exhibit 12	—	Computation of Ratio of Earnings to Fixed Charges.
*Exhibit 31.1	—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*Exhibit 31.2	—	Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**Exhibit 32	—	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*Exhibit 101.INS	—	XBRL Instance Document.
*Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema.
*Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase.
*Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase.
*Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase.
*Exhibit 101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase.

* Filed herewith.

** Furnished herewith.

54

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

THE WILLIAMS COMPANIES, INC.

(Registrant)

/S/ TED T. TIMMERMANS

Ted T. Timmermans

Vice President, Controller and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)

August 2, 2012

EXHIBIT INDEX

Exhibit No.		Description
Exhibit 3.1	—	Restated Certificate of Incorporation (filed on May 26, 2010, as Exhibit 3.1 to the Company’s Current Report on Form 8-K) and incorporated herein by reference.
Exhibit 3.2	—	Restated By-Laws (filed on May 26, 2010, as Exhibit 3.2 to the Company’s Current Report on Form 8-K) and incorporated herein by reference.
Exhibit 4.1	—	Indenture, dated as of July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on July 16, 2012 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.
Exhibit 4.2	—	Registration Rights Agreement, dated July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and the initial purchasers listed therein (filed on July 16, 2012 as Exhibit 10.1 to Transcontinental Gas Pipe Line Company LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.
*Exhibit 10.1	—	First Amendment to Contribution Agreement, dated as of April 27, 2012, between Caiman Energy, LLC and Williams Partners L.P.
*Exhibit 10.2	—	Form of 2012 Restricted Stock Unit Agreement among The Williams Companies, Inc. and nonmanagement directors.
* Exhibit 12	—	Computation of Ratio of Earnings to Fixed Charges.
* Exhibit 31.1	—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*Exhibit 31.2	—	Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**Exhibit 32	—	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*Exhibit 101.INS	—	XBRL Instance Document
*Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema
*Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase
*Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase

*Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase
*Exhibit 101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase

* Filed herewith.

** Furnished herewith.

EX-10.1

Exhibit 10.1

Execution Copy

FIRST AMENDMENT TO

CONTRIBUTION AGREEMENT

THIS FIRST AMENDMENT TO CONTRIBUTION AGREEMENT (this “Amendment”) is entered into as of April 27, 2012 by and between Caiman Energy, LLC, a Delaware limited liability company (“Contributor”), and Williams Partners L.P., a Delaware limited partnership (“Acquirer”). Each of the parties to this Amendment is sometimes referred to individually in this Amendment as a “Party” and both of the parties to this Amendment are sometimes collectively referred to in this Amendment as the “Parties.”

W I T N E S S E T H:

WHEREAS, the Parties have entered into that certain Contribution Agreement dated as of March 19, 2012 (the “Contribution Agreement”) with respect to the sale by Contributor to Acquirer of 100% of the outstanding membership interests of Caiman Eastern Midstream, LLC, a Texas limited liability company; and

WHEREAS, the Parties desire to amend the Contribution Agreement as set forth in this Amendment, and capitalized terms used but not otherwise defined herein shall have the meanings ascribed to them in the Contribution Agreement.

NOW, THEREFORE, in consideration of the foregoing and the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound hereby, the Parties agree as follows:

Section 1. Amendments to Contribution Agreement.

(a) Amendment to Section 1.1(a). Section 1.1(a) of the Contribution Agreement is hereby amended by amending and restating the following defined terms as set forth below:

““CNX Purchase Agreement” means that certain Purchase and Sale Agreement dated as of October 24, 2011 by and among CNX Gas Company LLC, CNX Land Resources Inc., Contributor and the Company.”

““Escrow Agent” means Deutsche Bank Trust Company Americas.”

(b) Amendment to Section 2.2(b). Section 2.2(b) of the Contribution Agreement is hereby amended by adding a new subsection (viii) as follows:

“(viii) Acquirer shall pay (A) to CNX Gas Company LLC (or one or more of its Affiliates designated prior to the Closing) an amount equal to $5,531,050.48 and (B) to Contributor an amount equal to $437,500.00 to be reserved for potential payment by Contributor to CNX Gas Company LLC pursuant to Section 5.20, such amounts together representing the purchase price for the Subject Pipeline Interest (as defined in the CNX Purchase Agreement).”

(c) Amendment to Section 3.8(a). Section 3.8(a) of the Contribution Agreement is hereby amended and restated in its entirety to read as follows:

“(a) Schedule 3.8(a) sets forth all of the following Contracts to which the Company is a party or by which it is bound or subject to as of the date of this Agreement or as of the Closing Date (collectively, the “Material Contracts”):

(i) any Contracts with customers pursuant to which the Company gathers, processes, treats, fractionates, transports, stores, sells or purchases oil, natural gas, condensate or natural gas liquids or other liquid or gaseous hydrocarbons or the products therefrom, or provides services related thereto (including any operation, operation servicing or maintenance Contract), other than, in each case, any such Contracts described in Section 3.8(a)(viii);

(ii) any Contracts in effect as of the date of this Agreement for the construction of gathering or other pipeline systems or processing, fractionation or storage facilities other than any such Contracts requiring aggregate payments of less than $1,000,000 or which are terminable by the Company on sixty (60) days’ notice or less without payment by the Company of any material penalty;

(iii) any Contracts (A) for the purchase or sale of any asset, equipment, supplies, goods or property or provision of any service or (B) that grant a right or option to purchase or sell any asset or property or receive services other than, in each case, (x) any such Contracts requiring aggregate payments of less than $1,000,000 or (y) any such Contracts described in Section 3.8(a)(i) or Section 3.8(a)(ii);

(iv) any Contracts providing for the lease of any item or items of personal or real property with annual rental expense under such lease in excess of $50,000 other than any such Contracts which are terminable by the Company on sixty (60) days’ notice or less without payment by the Company of any material penalty;

(v) any Contracts under which the Company has created, incurred, assumed or guaranteed any outstanding Indebtedness;

(vi) any Contracts between (A) the Company, on the one hand, and any current or former employee, officer, manager, member or Affiliate of the Company, on the other hand, (B) the Company and any Employee, or (C) the Company and Contributor or any of its Affiliates with respect to any Employee;

(vii) any collective bargaining Contracts;

(viii) any outstanding futures, swap, collar, put, call, floor, cap, option, hedging, forward sale or other derivative Contracts involving natural gas or other commodity sales or trading;

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(ix) any Contracts (A) that purport to limit in any respect the freedom of the Company to compete in any line of business or in any geographic area or not to solicit or hire any person with respect to employment or (B) that purport to limit in any respect the freedom of any other Person to compete with the Company in any line of business or in any geographical area or not to solicit or hire any person with respect to employment;

(x) any partnership, joint venture, strategic alliance or limited liability company agreements;

(xi) except as contemplated by clauses (i) and (ii) above, any sales, distribution or other similar agreement providing for the sale by any of the Company of materials, supplies, goods, services, equipment or other assets that provides for annual payments to the Company of $1,000,000 or more;

(xii) Contracts relating to the acquisition (by merger, purchase of stock or assets or otherwise) by the Company of any operating business or material assets or Equity Interests of any other Person;

(xiii) any Contract with a term of two (2) years or more and requiring aggregate payments by or to the Company in excess of $1,000,000 or, in any event, any Contract with a term of three (3) years or more, other than any such Contracts which are terminable by the Company on sixty (60) days’ notice or less without payment by the Company of any material penalty;

(xiv) any Contract under which the Company has made advances or loans to any other Person;

(xv) any material management Contract or any material Contract with independent contractors or consultants (or similar arrangements) that are not cancelable without penalty or further payment and on not more than thirty (30) days’ notice; and

(xvi) any other Contract not described in the foregoing clauses (i) through (xv) pursuant to which the Company has future liability in excess of $1,000,000 for any year or $3,000,000 in the aggregate and that cannot be terminated by the Company on not more than ninety (90) days’ notice or with payment by the Company of a penalty not in excess of $50,000.”

(d) Amendment to Section 3.11(c). Section 3.11(c) of the Contribution Agreement is hereby amended and restated in its entirety to read as follows:

“(c) Except with respect to Rights of Way (as defined below) necessary for those portions of the Company’s systems or facilities that are under construction and except as set forth on Schedule 3.11(c)(i): (i) each easement, license, right-of-way, Permit, servitude, leasehold estate, instrument creating an interest in real property, and other similar real estate interest of the Company (each, a “Right of Way”) is valid and free and clear of all Liens (other than Permitted Liens), (ii) the Company conducts its businesses in a manner that does not violate in any material respect any of the Rights of Way, (iii) the Company has fulfilled

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and performed in all material respects all of its obligations with respect to such Rights of Way, and (iv) the Company has not received written notice of the occurrence of any ongoing event or circumstance that allows, or after the giving of notice or the passage of time, or both, would allow limitation, revocation or termination of any Right of Way or would result in any impairment of the rights of the Company in and to any such Rights of Way. To the Knowledge of Contributor, all pipelines operated by the Company are subject to enforceable Rights of Way, and there are no gaps (including any gap arising as a result of any breach by the Company of the terms of any Rights of Way) in the pipeline systems for which enforceable Rights of Way, except those gaps listed on Schedule 3.11(c)(ii) and other immaterial gaps.”

(e) Amendments to Section 5.8(b).

(i) The first sentence of Section 5.8(b) of the Contribution Agreement is hereby amended and restated in its entirety to read as follows:

“(b) No later than seven (7) Business Days prior to the anticipated Closing Date, Acquirer or one or more of its Affiliates shall offer employment to each Employee whose names and positions are set forth on the document entitled “Covered Employees” made available to Acquirer in the virtual data room (the “Covered Employees”), which offers shall (i) be written offers of employment substantially consistent with the terms of this Section 5.8, (ii) be on terms or conditions comparable to similarly situated employees of Acquirer or its applicable Affiliate (with credit for all periods of employment or service with Contributor and its Affiliates (including, for the avoidance of doubt, service with the Co-Employer relating to Contributor and its Affiliates) prior to the Closing Date solely for purposes of paid time off and severance entitlement, and not for any other purpose under any employee benefit plan or program), and such Covered Employee shall be subject to the applicable screening and testing policies and procedures of Acquirer or its applicable Affiliate, and (iii) otherwise be consistent with standard terms, conditions and policies of employment of Acquirer or its applicable Affiliates (each a “Qualifying Offer”).”

(ii) The third sentence of Section 5.8(b) of the Contribution Agreement is hereby amended and restated in its entirety to read as follows:

“No later than one (1) Business Day before the anticipated Closing Date, Acquirer shall inform Contributor of the identities of those Covered Employees who have accepted Acquirer’s or such Affiliates Qualifying Offer and those, if any, who have declined the Qualifying Offer.”

(f) Amendment to Section 5.11. Section 5.11 of the Contribution Agreement is hereby amended and restated in its entirety to read as follows:

“Section 5.11 Repayment of Scheduled Debt. At least one (1) Business Day prior to the Closing, Contributor (a) shall obtain and deliver, or shall cause to be obtained and delivered, to Acquirer payoff letters from each financial institution or other lender in respect of any and all Indebtedness of the Company (including the Scheduled Debt), each in form and

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substance reasonably satisfactory to Acquirer, confirming the total payment required to be made as of the Closing Date to repay in full the amount of such Indebtedness and (b) shall authorize Acquirer to wire transfer a portion of the Cash Consideration directly to holders of the Scheduled Debt, on Contributor’s behalf, so to cause the amount of Scheduled Debt determined by Acquirer to be repaid and fully satisfied at the Closing to be so repaid and fully satisfied.”

(g) Amendments to Article 5.

(i) Article 5 of the Contribution Agreement is hereby amended by adding a new Section 5.19 as follows:

“Section 5.19 Certain Obligations of Contributor. After the Closing, Contributor shall make the $50,000 payment required to be made by Contributor to the West Virginia Department of Environmental Protection in accordance with the Order for Compliance contained in that certain Second Revised Consent Order No. 7467 dated December 12, 2011 between Contributor and the West Virginia Department of Environmental Protection.”

(ii) Article 5 of the Contribution Agreement is hereby amended by adding a new Section 5.20 as follows:

“Section 5.20 CNX Purchase Agreement. Promptly following the expiration of the Escrow Period, Contributor shall pay to CNX Gas Company, LLC an amount equal to $437,500.00, less any portion of such amount that is paid to any Acquirer Indemnified Party as Escrow Property pursuant the Escrow Agreement, with respect to the purchase of the Subject Pipeline Interest (as defined in the CNX Purchase Agreement) in accordance with that certain letter agreement dated April 26, 2012 between Contributor and CNX Gas Company LLC.”

(h) Amendment to Section 9.2(a). Section 9.2(a) of the Contribution Agreement is hereby amended and restated in its entirety to read as follows:

“(a) Effective after the Closing, subject to the terms and conditions of this Article 9, Contributor hereby indemnifies Acquirer, its Affiliates (including the Company) and their respective Representatives (collectively, the “Acquirer Indemnified Parties”) against and shall hold each of them harmless from any and all Losses, whether or not including a Third Party Claim, incurred or suffered by any such Acquirer Indemnified Party based upon, attributable to or resulting from:

(i) any inaccuracy in or breach of any representation or warranty made by Contributor in this Agreement or in any certificate delivered pursuant to Sections 2.2 or 7.2 (provided that, for the sole purpose of determining Losses (and not for determining whether or not any breaches of representations and warranties of Contributor have occurred), any qualification or exception contained therein relating to materiality (including Material Adverse Effect) shall be disregarded) or any breach of any covenant, agreement or obligation of Contributor contained in this Agreement to be performed prior to the Closing Date;

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(ii) any breach of any covenant, agreement or obligation of Contributor contained in this Agreement, other than those to be performed prior to the Closing Date;

(iii) any and all environmental liabilities incurred or suffered by the Company arising from or associated with the Company’s ownership of the Superfund Site;

(iv) any Pre-Closing Taxes;

(v) any claim, action or proceeding by a member of the CONSOL Group (as defined in the CNX Purchase Agreement) made pursuant to the CNX Purchase Agreement against any Acquirer Indemnified Party with respect to any actions of the Contributor occurring prior to the Closing; and

(vi) any matters identified in paragraph (3) of the certificate delivered or caused to be delivered by Contributor pursuant to Section 7.2(e) (the “Caiman Officer’s Certificate”), subject to the limitations set forth in the Caiman Officer’s Certificate.”

(i) Amendment to Section 9.2(b)(i). Section 9.2(b)(i) of the Contribution Agreement is hereby amended and restated in its entirety to read as follows:

“(i) Contributor shall not be liable for any Losses under Section 9.2(a)(i) except to the extent that the aggregate amount of such Losses equals or exceeds $12,500,000 (the “Basket Amount”), in which case Contributor shall only be liable for the amount of such Losses in excess of the Basket Amount; provided that, the foregoing limitation shall not apply with respect to any inaccuracy in or breach of any representation or warranty set forth in the Contributor Fundamental Representations, in the last sentence of Section 3.10(c) or in Section 3.16 (Taxes), or to Fraud on the part of Contributor or any breach of the covenants, agreements or obligations of Contributor set forth in Article 2;”

(j) Amendment to Section 9.2(b)(ii). Section 9.2(b)(ii) of the Contribution Agreement is hereby amended and restated in its entirety to read as follows:

“(ii) Contributor’s maximum liability for any Losses under Sections 9.2(a)(i) shall not exceed $175,000,000; provided that, the foregoing limitation shall not apply with respect to any inaccuracy in or breach of any representation or warranty set forth in the Contributor Fundamental Representations, in the last sentence of Section 3.10(c) or in Section 3.16 (Taxes), or to Fraud on the part of Contributor, and shall not apply to (A) any knowing and intentional breach by Contributor of any of the covenants, agreements or obligations of Contributor set forth in Article 5 that are to be performed prior to the Closing Date or (B) any breach of any of the covenants, agreements or obligations of Contributor set forth in Article 2;”

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(k) Amendment to Section 9.2(c). Section 9.2(c) of the Contribution Agreement is hereby amended and restated in its entirety to read as follows:

“(c) Effective after the Closing, subject to the terms and conditions of this Article 9, Acquirer hereby indemnifies Contributor, its Affiliates and their respective Representatives (collectively, the “Contributor Indemnified Parties”) against and shall hold each of them harmless from any and all Losses incurred or suffered by any such Contributor Indemnified Party based upon, attributable to or resulting from:

(i) any inaccuracy in or breach of any representation or warranty made by Acquirer in this Agreement or in any certificate delivered pursuant to Sections 2.2 or 7.3 (provided that, for the sole purpose of determining Losses (and not for determining whether or not any breaches of representations and warranties of Acquirer have occurred), any qualification or exception contained therein relating to materiality shall be disregarded);

(ii) any breach of any covenant, agreement or obligation of Acquirer contained in this Agreement; and

(iii) any claim, action or proceeding by a member of the CONSOL Group (as defined in the CNX Purchase Agreement) made against Contributor pursuant to the CNX Purchase Agreement arising out of or resulting from any matter occurring on or after the Closing.”

(l) Amendment to Section 9.2(e)(i). Section 9.2(e)(i) of the Contribution Agreement is hereby amended and restated in its entirety to read as follows:

“(i) If the Closing occurs, for any indemnification claims under Section 9.2(a)(i), the Escrow Property shall be the Acquirer Indemnified Parties’ sole and exclusive security and source of consideration and recovery, and the transfer of Escrow Units or payment of cash from the Escrow Account shall be the Acquirer Indemnified Parties’ sole and exclusive remedy therefor; provided that, the limitation in this Section 9.2(e)(i) shall not apply with respect to any inaccuracy in or breach of any representation or warranty set forth in the Contributor Fundamental Representations, in the last sentence of Section 3.10(c) or in Section 3.16 (Taxes) or to any knowing and intentional breach by Contributor of any of the covenants, agreements or obligations of Contributor set forth in Article 5 that are to be performed prior to the Closing Date or any breach of any of the covenants, agreements or obligations of Contributor set forth in Article 2. Acquirer Indemnified Parties shall not be limited to the Escrow Property for indemnification claims based on (A) Fraud on the part of Contributor, (B) Sections 9.2(a)(ii), 9.2(a)(iii) or 9.2(a)(iv), or (C) matters described in the proviso of the immediately preceding sentence, and they shall have the right to seek indemnification directly against Contributor without first exhausting the Escrow Property or seeking indemnification against the Escrow Account; provided that, Contributor may, in its sole discretion, satisfy any such indemnification claims by paying cash or delivering WPZ Units (in each case, other than the Escrow Property) to Acquirer in satisfaction of any such claim.”

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(m) Amendment to Schedule 3.8(a). Schedule 3.8(a) to the Contribution Agreement is hereby amended by amending and restating in their entirety the numbered items on Schedule 3.8(a) set forth below:

“27. Operational Balancing Agreement between Texas Eastern Transmission, LP and Caiman Energy, LLC dated February 1, 2010, not amended, as superseded by that certain Operational Balancing Agreement, effective as of March 23, 2012, between Caiman Eastern Midstream, LLC and Texas Eastern Transmission, LP.”

“29. Marketing Services Agreement between Inergy Propane LLC and Caiman Energy, LLC dated January 1, 2011, as amended by that Letter Agreement between Inergy Propane LLC and Caiman Energy, LLC dated July 14, 2011, including the related Assignment, effective as of April 1, 2012, between Caiman Energy, LLC and Caiman Eastern Midstream, LLC.”

“37. Plant Equipment Contract for a 200 MM Cryogenic Plant (Plant III) between Caiman Energy, LLC and Thomas Russell, LLC d/b/a Thomas Russell Co. dated May 31, 2011, not amended including the related Assignment, effective as of April 1, 2012, between Caiman Energy, LLC and Caiman Eastern Midstream, LLC.”

“38. Plant Equipment Contract for a 200 MM Cryogenic Plant with 4500 HP Refrigeration System (Plant IV) between Caiman Energy, LLC and Thomas Russell, LLC d/b/a Thomas Russell Co. dated October 1, 2011, not amended, including the related Assignment, effective as of April 1, 2012, between Caiman Energy, LLC and Caiman Eastern Midstream, LLC.”

“43. Gas Compression Master Service Agreement between USA Compression and Caiman Energy, LLC dated July 26, 2010. (Schedules have been updated and/or amended for each compressor leased, but no amendment to the base MSA.), as superseded in part by that certain Gas Compression Master Service Agreement between USA Compression and Caiman Eastern Midstream, LLC dated April 1, 2012.”

“45. Master Compression Services Agreement between EXLP Operating LLC and Caiman Energy, LLC dated December 1, 2009, not amended, including the related Assignment, effective as of April 1, 2012, between Caiman Energy, LLC and Caiman Eastern Midstream, LLC.”

(n) Amendment to Schedule 3.11(c)(i). Schedule 3.11(c)(i) to the Contribution Agreement is hereby amended by amending and restating in their entirety the numbered items on Schedule 3.11(c)(i) as set forth on Exhibit A.

(o) Amendment to Schedule 5.1(b). Schedule 5.1(b) to the Contribution Agreement is hereby amended by adding a new item 3. as follows:

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“3. Contributor and the Company expect to enter into a letter agreement with CNX Gas Company LLC, CNX Land Resources Inc. amending that certain Purchase and Sale Agreement dated as of October 24, 2011 by and among CNX Gas Company LLC, CNX Land Resources Inc., Contributor and the Company to release Contributor from any obligations under such Purchase and Sale Agreement following the Closing.”

Section 2. General Provisions.

(a) Modifications. No amendments or modifications of this Amendment shall be valid unless such amendments or modifications are made in accordance with Section 10.2 of the Contribution Agreement.

(b) Effect of the Amendment. Except as amended by this Amendment, all other terms of the Contribution Agreement shall continue in full force and effect and remain unchanged and are hereby confirmed in all respects by the Parties.

(c) Partial Invalidity. If any term, provision, covenant, or condition of this Amendment is held by a court of competent jurisdiction to be invalid, void, or unenforceable, the rest of this Amendment shall remain in full force and effect and in no way be affected, impaired or invalidated.

(d) Governing Law. This Amendment shall be governed by and construed in accordance with the law of the State of Texas, without regard to the conflicts of law rules thereof.

(e) Counterparts. This Amendment may be signed in any number of counterparts (including facsimile and electronic transmission counterparts), each of which shall be an original, with the same effect as if the signatures to this Amendment were upon the same instrument. This Amendment shall become effective when each Party shall have received a counterpart of this Amendment signed by the other Parties. Until and unless each Party has received a counterpart of this Amendment signed by the other Parties, this Amendment shall have no effect and no Party shall have any right or obligation under this Amendment (whether by virtue of any other oral or written agreement or other communication).

[Signature Page Follows]

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IN WITNESS WHEREOF, the Parties have caused this Amendment to be duly executed by their respective authorized officers as of the date first written above.

CAIMAN ENERGY, LLC
By:	/s/ Stephen L. Arata
Name: Stephen L. Arata
Title:    Senior Vice President and Chief Financial Officer
WILLIAMS PARTNERS L.P.
By:	Williams Partners GP LLC,
	its General Partner
	By:	/s/ James E. Scheel
	Name: James E. Scheel
	Title:    Senior Vice President – Corporate Strategic Development

[SIGNATURE PAGE TO FIRST AMENDMENT TO

CONTRIBUTION AGREEMENT]

EXHIBIT A

SCHEDULE 3.11(c)(i)

RIGHTS-OF-WAY

	County, State/ District/ Acreage	Parcel ID #	Grantor	Grantee
13.	Monroe, OH Ohio Township	15-005008.0000 15-013010.0000 15-013010.1000 15-013010.2000 15-005009.0000 15-013007.0000	Tony Schindler and Terri Schindler	Caiman Ohio Midstream, LLC
14.	Monroe, OH Ohio Township	15-005008.0000 15-013010.0000 15-013010.1000 15-013010.2000 15-005009.0000 15-013007.0000	Tony Schindler and Terri Schindler	Caiman Ohio Midstream, LLC
15.	Monroe, OH Ohio Township	15-005008.0000 15-013010.0000 15-013010.1000 15-013010.2000 15-005009.0000 15-013007.0000	Tony Schindler and Terri Schindler	Caiman Ohio Midstream, LLC

EXHIBIT A

EX-10.2

Exhibit 10.2

[Date]

TO:	[Name]
FROM:	Alan S. Armstrong
SUBJECT:	2012 Restricted Stock Unit Award

You have been granted a restricted stock unit award. This award, which is subject to adjustment under the 2012 Restricted Stock Unit Agreement (the “Agreement”), is granted to you in recognition of your role as a non-management director for The Williams Companies, Inc. It is granted and subject to the terms and conditions of The Williams Companies, Inc. 2007 Incentive Plan, as amended and restated from time to time, and the Agreement.

Subject to all of the terms of the Agreement, you will become entitled to payment of this award one year after the date on which this award is made.

If you have any questions about this award, you may contact a dedicated Fidelity Stock Plan Representative at 1-800-544-9354.

2012 RESTRICTED STOCK UNIT AGREEMENT

THIS RESTRICTED STOCK UNIT AGREEMENT (this “Agreement”), which contains the terms and conditions for the Restricted Stock Units (“Restricted Stock Units” or “RSUs”) referred to in the 2012 Restricted Stock Unit Award Letter delivered in hard copy or electronically to Participant (“2012 Award Letter”), is by and between THE WILLIAMS COMPANIES, INC., a Delaware corporation (the “Company”) and the individual identified on the last page hereof (the “Participant”).

1. Grant of RSUs. Subject to the terms and conditions of The Williams Companies, Inc. 2007 Incentive Plan, as amended and restated from time to time (the “Plan”), this Agreement and the 2012 Award Letter, the Company hereby grants an award (the “Award”) to the Participant of [Number] RSUs effective [Date] (the “Effective Date”). The Award gives the Participant the right to receive the number of shares of the Common Stock of the Company equal to the number of RSUs shown in the prior sentence, subject to adjustment under the terms of this Agreement. These shares are referred to in this Agreement as the “Shares.” Until the Participant receives payment of the Shares under the terms of Paragraph 4, the Participant shall have no rights as a stockholder of the Company with respect to the Shares, except for the right to earn Dividend Equivalents as set forth herein.

2. Incorporation of Plan and Acceptance of Documents. The Plan is hereby incorporated herein by reference and all capitalized terms used herein which are not defined in this Agreement shall have the respective meanings set forth in the Plan. The Participant acknowledges that he or she has received a copy of, or has online access to, the Plan and hereby automatically accepts the RSUs subject to all the terms and provisions of the Plan and this Agreement. The Participant hereby further agrees that he or she has received a copy of, or has online access to, the prospectus and hereby acknowledges his or her automatic acceptance and receipt of such prospectus electronically.

3. Board Decisions and Interpretations. The Participant hereby agrees to accept as binding, conclusive and final all actions, decisions and/or interpretations of the Board, its delegates, or agents, upon any questions or other matters arising under the Plan or this Agreement.

4. Payment of Shares; Dividend Equivalents.

(a) Except as otherwise provided in Subparagraph 4(b) below, the Participant shall receive payment of all Shares on the date that is one year after the Effective Date (not including the Effective Date) (the “Maturity Date”). For example, if the Effective Date of the Participant’s award under this Agreement is May         , 2012, the Maturity Date will be May         , 2013.

(b) If the Participant dies prior to the Maturity Date while serving as a Non-Management Director of the Company or his or her service as a Non-Management Director of the Company terminates for any other reason prior to the Maturity Date and such termination constitutes a “separation from service” as defined under Treasury Regulation § 1.409A-1, as amended, the Participant shall receive payment of all Shares at

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the time of such death or separation from service. In this regard, if at the time a Non-Management Director’s service as a Non-Management Director terminates, such Non-Management Director is also providing services to the Company or an Affiliate (as defined below) as an independent contractor, no separation from service by such Non-Management Director shall occur and no Shares shall be payable to such Non-Management Director until the date on which such Non-Management Director has a Separation from Service as an Independent Contractor (as defined below) from the Company and its Affiliates.

(c) All Shares that are paid pursuant to the Participant’s death or separation from service Subparagraph 4(b) above shall be paid to the Participant upon occurrence of the event giving rise to the right to payment or, in the case of Participant’s death, to the beneficiary of the Participant under the Plan or, if no beneficiary has been designated, to the Participant’s estate, provided that, except as otherwise required under Federal securities laws or other applicable law, all Shares that are paid pursuant to Subparagraph 4(b) above shall be paid not more than 90 days following the occurrence of the event giving rise to the right to payment.

(d) Shares that become payable under this Agreement will be paid by the Company by the delivery to the Participant, or, in the case of the Participant’s death, to the Participant’s beneficiary or legal representative, of one or more certificates (or other indicia of ownership) representing shares of Williams Common Stock equal in number to the number of Shares otherwise payable under this Agreement.

(e) Upon conversion of RSUs into Shares under this Agreement, such RSUs shall be cancelled.

(f) From and after the Effective Date, the Participant shall be entitled to accrue Dividend Equivalents with respect to each Share subject to the Award. Such Dividend Equivalents shall accrue in cash as and when dividends are paid to stockholders generally. Prior to payment, the Dividend Equivalents shall be subject to the same restrictions and limitations set forth herein with respect to the RSUs to which the Dividend Equivalents relate. The Dividend Equivalents accrued hereunder shall be paid in cash in lump sum (without interest) to the Participant (or beneficiary or estate, as applicable) as and when the Shares to which such Dividend Equivalents relate are paid pursuant to this Section 4.

5. Definitions. As used in this Agreement, the following terms shall have the definitions set forth below.

(a) “Affiliate” means all persons with whom the Company would be considered a single employer under Section 414(b) of the Code, and all persons with whom such person would be considered a single employer under Section 414(c) of the Code.

(b) “Separation from Service as an Independent Contractor” will occur upon the expiration of the contract (or in the case of more than one contract, all contracts) under which services are performed by a Non-Management Director for the Company or an

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Affiliate, but only if the expiration constitutes a good-faith and complete termination of the contractual relationship. An expiration of a contract shall not constitute a good faith and complete termination of the contractual relationship if the Company or an Affiliate anticipates either a renewal of a contractual relationship or the Non-Management Director’s becoming an employee. The determination of whether a Separation from Service as an Independent Contractor has occurred shall be governed by the provisions of Treasury Regulation § 1.409A-1, as amended.

6. Other Provisions.

(a) The Participant understands and agrees that payments under this Agreement shall not be used for, or in the determination of, any other payment or benefit under any continuing agreement, plan, policy, practice or arrangement providing for the making of any payment or the provision of any benefits to or for the Participant or the Participant’s beneficiaries or representatives, including, without limitation, any employment agreement, any change of control severance protection plan or any employee benefit plan as defined in Section 3(3) of ERISA, including, but not limited to qualified and non-qualified retirement plans.

(b) The Participant agrees and understands that, upon payment of Shares under this Agreement, stock certificates (or other indicia of ownership) issued may be held as collateral for monies he/she owes to Company or any of its Affiliates, including but not limited to personal loan(s) or Company credit card debt.

(c) RSUs, Shares and the Participant’s interest in RSUs and Shares may not be sold, assigned, transferred, pledged or otherwise disposed of or encumbered at any time prior to the Participant’s becoming entitled to payment of Shares under this Agreement.

(d) With respect to the right to receive payment of the Shares under this Agreement, nothing contained herein shall give the Participant any rights that are greater than those of a general creditor of the Company.

(e) The obligations of the Company under this Agreement are unfunded and unsecured. Each Participant shall have the status of a general creditor of the Company with respect to amounts due, if any, under this Agreement.

(f) The parties to this Agreement intend that this Agreement meet the applicable requirements of Section 409A of the Code and recognize that it may be necessary to modify this Agreement and/or the Plan to reflect guidance under Section 409A of the Code issued by the Internal Revenue Service. Participant agrees that the Board shall have sole discretion in determining (i) whether any such modification is desirable or appropriate and (ii) the terms of any such modification.

(g) The Participant hereby automatically becomes a party to this Agreement whether or not he or she accepts the Award electronically or in writing in accordance with procedures of the Board, its delegates or agents.

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(h) Nothing in this Agreement or the Plan shall confer upon the Participant the right to continue to serve as a director of the Company.

(i) The Participant hereby acknowledges that nothing in this Agreement shall be construed as requiring the Board or Committee to allow a Domestic Relations Order with respect to this Award.

7. Notices. All notices to the Company required hereunder shall be in writing and delivered by hand or by mail, addressed to The Williams Companies, Inc., One Williams Center, Tulsa, Oklahoma 74172, Attention: Stock Administration Department. Notices shall become effective upon their receipt by the Company if delivered in the foregoing manner. To direct the sale of any Shares issued under this Agreement, the Participant must contact Fidelity at http://netbenefits.fidelity.com or by telephone at 800-544-9354.

8. Tax Consultation. You understand you will incur tax consequences as a result of acquisition or disposition of the Shares. You agree to consult with any tax consultants you think advisable in connection with the acquisition of the Shares and acknowledge that you are not relying, and will not rely, on the Company for any tax advice.

THE WILLIAMS COMPANIES, INC.
By:
	Alan S. Armstrong
	President and CEO

Participant: [Name]

SSN: [SSN]

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EX-12

Exhibit 12

The Williams Companies, Inc.

Computation of Ratio of Earnings to Fixed Charges

	Six months ended June 30, 2012
	(Millions)
Earnings:
Income from continuing operations before income taxes	$	729
Less: Equity earnings, excluding proportionate share from 50% owned investees and unconsolidated majority-owned investees		(14	)
Income from continuing operations before income taxes and equity earnings		715
Add:
Fixed charges:
Interest accrued, including proportionate share from 50% owned investees and unconsolidated majority-owned investees (a)		299
Rental expense representative of interest factor		6
Total fixed charges		305
Distributed income of equity-method investees, excluding proportionate share from 50% owned investees and unconsolidated majority-owned investees		28
Less:
Capitalized interest		(22	)
Total earnings as adjusted	$	1,026
Fixed charges	$	305
Ratio of earnings to fixed charges		3.36

(a) Does not include interest related to income taxes, including interest related to liabilities for uncertain tax positions, which is included in provision (benefit) for income taxes in our Consolidated Statement of Income.

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Alan S. Armstrong, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Williams Companies, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2012

/s/ Alan S. Armstrong

Alan S. Armstrong

President and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Donald R. Chappel, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Williams Companies, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2012

/s/ Donald R. Chappel

Donald R. Chappel

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of The Williams Companies, Inc. (the “Company”) on Form 10-Q for the period ending June 30, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of the Company, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Alan S. Armstrong

Alan S. Armstrong

President and Chief Executive Officer

August 2, 2012

/s/ Donald R. Chappel

Donald R. Chappel

Chief Financial Officer

August 2, 2012

A signed original of this written statement required by Section 906 has been provided to, and will be retained by, the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report and shall not be considered filed as part of the Report.

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Earnings (Loss) Per Common Share from Continuing Operations (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Earnings (loss) per common share from continuing operations
Income (loss) from continuing operations attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$ 133	$ 171	$ 420	$ 471
Basic weighted-average shares	621,483,000	588,310,000	607,357,000	587,641,000
Effect of dilutive securities:
Diluted weighted-average shares	626,620,000	597,633,000	613,570,000	597,097,000
Earnings (loss) per common share from continuing operations:
Basic	$ 0.21	$ 0.29	$ 0.69	$ 0.80
Diluted	$ 0.21	$ 0.29	$ 0.68	$ 0.79
Stock options excluded
Weighted-average exercise price of options excluded		$ 36.47		$ 36.47
Exercise price ranges of options excluded, minimum		$ 32.05		$ 32.05
Exercise price ranges of options excluded, maximum		$ 37.88		$ 37.88
Quarter Weighted Average Market Price	$ 30.93	$ 30.54	$ 30.93	$ 30.54
Nonvested Restricted Stock Units
Effect of dilutive securities:
Incremental common shares attributable to share-based payment arrangements under effects of dilutive securities item	2,109,000	3,887,000	2,836,000	4,005,000
Stock options
Effect of dilutive securities:
Incremental common shares attributable to share-based payment arrangements under effects of dilutive securities item	2,614,000	3,537,000	2,776,000	3,501,000
Convertible debentures
Effect of dilutive securities:
Incremental dilutive shares, Convertible debt	414,000	1,899,000	601,000	1,950,000
Out of the Money Options
Earnings (loss) per common share from continuing operations (Textuals) [Abstract]
Number of weighted-average shares excluded from computation of diluted earnings per common share			0	1,000,000

XML

Segment Disclosures (Details Textual) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011
Segment Disclosures [Abstract]
Revenues from former exploration and production business now shown as external	$ 78	$ 152
Costs attributable to former exploration and production business now shown as external	$ 219	$ 429

XML

Derivative Instruments (Details 1) (Risk Management)	Jun. 30, 2012 bbl
Central Hub Risk | Midstream Canada & Olefins [Member]
Derivative Instruments Not Designated as Hedging Instruments
Net notional quantity of price risk derivative instruments not designated as hedging instruments	(220,000)
Central Hub Risk | Williams Partners [Member]
Derivative Instruments Designated as Hedging Instruments
Net notional quantity of derivative designated as hedging instrument	7,810,800
Derivative Instruments Not Designated as Hedging Instruments
Net notional quantity of price risk derivative instruments not designated as hedging instruments	115,000
Basis Risk | Williams Partners [Member]
Derivative Instruments Designated as Hedging Instruments
Net notional quantity of derivative designated as hedging instrument	6,504,400
Derivative Instruments Not Designated as Hedging Instruments
Net notional quantity of price risk derivative instruments not designated as hedging instruments	255,000

XML

Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Carrying Amount [Member]
Additional disclosure: [Abstract]
Notes receivable and other	$ 131	$ 57
Long-term debt, including current portion	(9,034)	(8,718)
Guarantee	(33)	(34)
Customer margin deposits payable	(32)
Fair Value [Member]
Additional disclosure: [Abstract]
Notes receivable and other	133	57
Long-term debt, including current portion	(10,426)	(10,043)
Guarantee	(31)	(32)
Customer margin deposits payable	(32)
Level 1 [Member]
Additional disclosure: [Abstract]
Notes receivable and other	6
Long-term debt, including current portion	0
Guarantee	0
Customer margin deposits payable	(32)
Level 2 [Member]
Additional disclosure: [Abstract]
Notes receivable and other	9
Long-term debt, including current portion	(10,426)
Guarantee	(31)
Customer margin deposits payable	0
Level 3 [Member]
Additional disclosure: [Abstract]
Notes receivable and other	118
Long-term debt, including current portion	0
Guarantee	0
Customer margin deposits payable	0
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member]
Measured on a recurring basis: [Abstract]
ARO Trust investments	25	25
Available-for-sale equity securities		24
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member] | Designated as Hedging Instrument [Member]
Measured on a recurring basis: [Abstract]
Energy derivatives assets	41
Fair Value, Measurements, Recurring [Member] | Carrying Amount [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis: [Abstract]
Energy derivatives assets	5	1
Energy derivatives liabilities	(5)
Fair Value, Measurements, Recurring [Member] | Fair Value [Member]
Measured on a recurring basis: [Abstract]
ARO Trust investments	25	25
Available-for-sale equity securities		24
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Designated as Hedging Instrument [Member]
Measured on a recurring basis: [Abstract]
Energy derivatives assets	41
Fair Value, Measurements, Recurring [Member] | Fair Value [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis: [Abstract]
Energy derivatives assets	5	1
Energy derivatives liabilities	(5)
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Measured on a recurring basis: [Abstract]
ARO Trust investments	25	25
Available-for-sale equity securities		24
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Designated as Hedging Instrument [Member]
Measured on a recurring basis: [Abstract]
Energy derivatives assets	29
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis: [Abstract]
Energy derivatives assets	2	1
Energy derivatives liabilities	(3)
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Measured on a recurring basis: [Abstract]
ARO Trust investments	0	0
Available-for-sale equity securities		0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Designated as Hedging Instrument [Member]
Measured on a recurring basis: [Abstract]
Energy derivatives assets	12
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis: [Abstract]
Energy derivatives assets	3	0
Energy derivatives liabilities	(2)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Measured on a recurring basis: [Abstract]
ARO Trust investments	0	0
Available-for-sale equity securities		0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Designated as Hedging Instrument [Member]
Measured on a recurring basis: [Abstract]
Energy derivatives assets	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Not Designated as Hedging Instrument [Member]
Measured on a recurring basis: [Abstract]
Energy derivatives assets	0	0
Energy derivatives liabilities	$ 0

XML

Acquisitions (Details) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended	2 Months Ended	4 Months Ended	6 Months Ended
	Jun. 30, 2012	Feb. 17, 2012 Laser [Member] Williams Partners [Member] Miles Inches	Apr. 27, 2012 Caiman [Member] Williams Partners [Member]	Jun. 30, 2012 Caiman [Member] Williams Partners [Member]
Business Acquisition, Entity Acquired and Reason for Acquisition [Abstract]
Business Acquisition, Percentage of Voting Interests Acquired		100.00%	100.00%
Business Acquisition, Cost of Acquired Entity, Purchase Price [Abstract]
Business Acquisition, Cost of Acquired Entity, Cash Paid		$ 325	$ 1,720
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares		7,531,381	11,779,296
Business Acquisition, Cost of Acquired Entity, Equity Interests Issued and Issuable		441	603
Number Of Miles Of Pipeline Acquired In Pennsylvania		33
Diameter In Inches Of Pipeline Acquired In Pennsylvania		16
Number of miles of pipeline acquired in New York		10
Business Combination, Acquisition Related Costs				16
Business Acquisition, Purchase Price Allocation [Abstract]
Assets held for sale		18	0
Other current assets		3	13
Property, plant and equipment		158	665
Intangible assets		318	1,313
Current liabilities		(21)	(98)
Identifiable net assets acquired		476	1,893
Goodwill		290	434
Total		766	2,327
Finite-Lived Intangible Assets [Abstract]
Acquired Finite-lived Intangible Asset, Weighted Average Useful Life (years)	30
Business Acquisition, Purchase Price Allocation, Goodwill [Abstract]
Business Acquisition, Purchase Price Allocation, Goodwill, Expected Tax Deductible Amount		$ 290	$ 434

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Provision (Benefit) for Income Taxes (Tables)

6 Months Ended

Jun. 30, 2012

Provision (Benefit) for Income Taxes [Abstract]

Provision (benefit) for income taxes from continuing operations

		Three months ended				Six months ended
		June 30,				June 30,
			2012		2011		2012		2011
			(Millions)				(Millions)
Current:
	Federal	$	33	$	59	$	54	$	88
	State		4		5		8		8
	Foreign		3		14		24		(6)
			40		78		86		90
Deferred:
	Federal		30		25		117		(7)
	State		(3)		2		(6)		(1)
	Foreign		4		4		7		5
			31		31		118		(3)
Total provision (benefit)		$	71	$	109	$	204	$	87

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Derivative Instruments (Details 3) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Revenues
Pre-tax gains and losses for our energy commodity derivatives not designated as hedging instruments
Net gain (loss)	$ 2	$ 0	$ 3	$ (1)
Costs and operating expenses
Pre-tax gains and losses for our energy commodity derivatives not designated as hedging instruments
Net gain (loss)			$ 0

XML

Debt and Banking Arrangements (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012
$ 900 million unsecured credit facility
Letters of credit issued and loans outstanding under line of credit facilities
Letters of Credit Outstanding, Amount	$ 0
Loans outstanding	0
$ 2 billion WPZ unsecured credit facility
Letters of credit issued and loans outstanding under line of credit facilities
Letters of Credit Outstanding, Amount	0
Loans outstanding	345
Line of Credit Facility, Maximum Borrowing Capacity	2,000
Bilateral bank agreements for letters of credit
Letters of credit issued and loans outstanding under line of credit facilities
Letters of Credit Outstanding, Amount	$ 24

XML

Asset Sales and Other Accruals (Details 1) (Other [Member], USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Other [Member]
Component of Other Expense, Nonoperating [Line Items]
Equity Method Investment, Realized Gain (Loss) on Disposal	$ 63	$ 11

XML

Contingent Liabilities (Details Textual) (USD $) In Millions, unless otherwise specified										1 Months Ended
	Jun. 30, 2012	Jan. 28, 2008 Gulsby-Bay	Jan. 28, 2008 Gulsby	Jun. 30, 2012 Gas Pipeline	Jun. 30, 2012 Former Operations	Jun. 30, 2012 Natural gas underground storage facilities	Dec. 31, 2011 Gulf Liquids	Dec. 31, 2008 Gulf Liquids	Dec. 31, 2006 Gulf Liquids	Feb. 28, 2011 Pending or Threatened Litigation
Contingent Liabilities (Textuals) [Abstract]
Accrued environmental loss liabilities	$ 45			$ 9	$ 28	$ 8
Estimated exposure for actual damages									68
Potential interest in addition to actual damages									20
Possible ultimate judgement in excess of accrual									199
Litigation award against Gulf Liquids, Damages		4	11
Loss contingency accrual reduction							33	43
Loss contingency accrued interest reduction							14	11
Assertion of Counterclaim										200
Loss Contingency, Range of Possible Loss, Maximum	$ 32

XML

Fair Value Measurements (Details Textual) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012 WPX Guarantee	Jun. 30, 2012 WilTel Guarantee	Dec. 31, 2011 WilTel Guarantee
Fair Value Measurements [Abstract]
Duration of energy derivatives contracts	9 months
Fair Value, Level 1 to level 2 Transfers, Amount	$ 0	$ 0
Fair Value, Level 2 to level 1 Transfers, Amount	0	0
Guarantor Obligations [Line Items]
Maximum potential exposure of guarantee			$ 245	$ 37	$ 38

XML

General, Description of Business, and Basis of Presentation

6 Months Ended

Jun. 30, 2012

General, Description of Business, and Basis of Presentation [Abstract]

General, Description of Business, and Basis of Presentation [Text Block]

Note 1. General, Description of Business and Basis of Presentation

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 Form 10-K/A Amendment No. 2, filed May 1, 2012. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements.

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.

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us,” or similar language refer to The Williams Companies, Inc. and its subsidiaries.

Description of Business

Our operations are located principally in the United States and are organized into the Williams Partnersand Midstream Canada & Olefins reporting segments. All remaining business activities are included in Other.

Williams Partners consists of our consolidated master limited partnership, Williams Partners L.P. (WPZ) and includes gas pipeline and domestic midstream businesses. The gas pipeline businesses include 100percent of Transcontinental Gas Pipe Line Company, LLC (Transco), 100percent of Northwest Pipeline GP (Northwest Pipeline), and 50percent 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 the Marcellus Shale region, and various equity investments in domestic natural gas gathering andprocessing assets and natural gas liquid (NGL) fractionation and transportation assets. WPZ's midstream assets also include substantial operations and investments in the Four Corners region, the Piceance basin, as well as an NGL fractionator and storage facilities near Conway, Kansas.

Our Midstream Canada & Olefins segment includes our oil sands offgas 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, as well as corporate operations.

Basis of Presentation

Master limited partnership

During the first quarter of 2012, WPZ completed a public equity issuance of 8,050,000 common units representing limited partner interests. WPZ also issued 7,531,381 common units to the seller in connection with its acquisition of certain entities from Delphi Midstream Partners, LLC. (See Note 2). During the second quarter of 2012, WPZ completed a public equity issuance of 10,973,368common units representing limited partner interests. WPZ also issued 11,779,296 common units to the seller in connection with its acquisition ofCaiman Eastern Midstream, LLC (See Note 2). In connection with the closing of this acquisition, we purchased 16,360,133additional WPZ common units. Following these transactions, as of June 30, 2012, we own approximately 68 percent of the interests in WPZ, including the interests of the general partner, which are wholly owned by us, and incentive distribution rights.

The previously described equity issuances by WPZ had the combined net impact of increasing our noncontrolling interests in consolidated subsidiaries by $1.382 billion, capital in excess of par value by $460 million and deferred income taxes by $273 million in the Consolidated Balance Sheet.

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.

Variable interest entity

Gulfstar One (Gulfstar) is a consolidated wholly-owned subsidiary that, due to certain risk sharing provisions in its customer contracts, is a variable interest entity. WPZ, as construction agent for Gulfstar, will design, construct, and install a proprietary floating-production system, Gulfstar FPS™, and associated pipelines which will initially provide production handling and gathering services for the Tubular Bells oil and gas discovery in the eastern deepwater Gulf of Mexico. Construction is underway and the project is expected to be in service in 2014. WPZ, in combination with certain advance payments from the producer customers, is currently financing the asset construction. As of June 30, 2012, theConsolidated Balance Sheet includes$305 million of Gulfstar construction work in process representing costs incurred to date, included in property, plant, and equipment, at costand $110 million of deferred revenue, included inregulatory liabilities, deferred income, and other associated with the customer advance payments.We are committed to the producer customers to construct this system, and we currently estimate the remaining construction cost to be less than $650 million. If the producer customers do not develop the offshore oil and gas fields to be connected to Gulfstar, they will be responsible for the firm price of building the facilities.

Discontinued operations

On December 31, 2011, we completed the tax-free spin-off of our 100 percent interest in WPX Energy, Inc. (WPX), to our shareholders. The spin-off was completed by means of a special stock dividend, which consisted of a distribution of one share of WPX common stock for every three shares of our common stock.For periods prior to the spin-off, the accompanying Consolidated Statement of Income reflects the results of operations of our former exploration and production business as discontinued operations.  (See Note 3.)

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

XML

Debt and Banking Arrangements (Details Textual) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012
$ 900 million unsecured credit facility effective June 2011
Debt and Banking Arrangements (Textuals) [Abstract]
Amount of unsecured credit facility	$ 900
$ 900 million unsecured credit facility effective June 2011 | Letter of Credit Capacity
Debt and Banking Arrangements (Textuals) [Abstract]
Amount of unsecured credit facility	700
$ 2 billion WPZ unsecured credit facility
Debt and Banking Arrangements (Textuals) [Abstract]
Amount of unsecured credit facility	2,000
$ 2 billion WPZ unsecured credit facility | Letter of Credit Capacity
Debt and Banking Arrangements (Textuals) [Abstract]
Amount of unsecured credit facility	$ 1,300

XML

Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2012

Fair Value Measurements [Abstract]

Carrying amounts and fair values of financial instruments

								Fair Value Measurements Using
									Quoted
									Prices In
									Active		Significant
									Markets for		Other		Significant
									Identical		Observable		Unobservable
				Carrying		Fair			Assets		Inputs		Inputs
				Amount		Value			(Level 1)		(Level 2)		(Level 3)
				(Millions)
Assets (liabilities) at June 30, 2012:
	Measured on a recurring basis:
		ARO Trust investments		$	25	$	25		$	25	$	-	$	-
		Energy derivatives assets not designated as
			hedging instruments		5		5			2		3		-
		Energy derivatives assets designated as hedging
			instruments		41		41			29		12		-
		Energy derivatives liabilities not designated as
			hedging instruments		(5)		(5)			(3)		(2)		-
	Additional disclosures:
		Notes receivable and other			131		133			6		9		118
		Long-term debt, including current portion (a)			(9,034)		(10,426)			-		(10,426)		-
		Guarantee			(33)		(31)			-		(31)		-
		Customer margin deposits payable			(32)		(32)			(32)		-		-
Assets (liabilities) at December 31, 2011:
	Measured on a recurring basis:
		ARO Trust investments		$	25	$	25		$	25	$	-	$	-
		Available-for-sale equity securities			24		24			24		-		-
		Energy derivatives assets not designated as
			hedging instruments		1		1			1		-		-
	Additional disclosures:
		Notes receivable and other			57		57			N/A		N/A		N/A
		Long-term debt, including current portion (a)			(8,718)		(10,043)			N/A		N/A		N/A
		Guarantee			(34)		(32)			N/A		N/A		N/A
(a) Excludes capital leases

XML

Inventories (Tables)

6 Months Ended

Jun. 30, 2012

Inventory [Abstract]

Inventories

	June 30,		December 31,
	2012		2011
		(Millions)
Natural gas liquids, olefins, and natural gas in underground storage	$	86	$	98
Materials, supplies, and other		73		71
	$	159	$	169

XML

Debt and Banking Arrangements (Details Textual 2) (Unsecured Debt Member, Transcontinental Gas Pipe Line Company, LLC [Member], USD $) In Millions, unless otherwise specified			1 Months Ended
	Aug. 31, 2011 $375 million (5.4%)	Jul. 31, 2012 $400 million (4.45%)	Jul. 31, 2012 $325 million (8.875%)
Debt Instrument [Line Items]
Repayments of Unsecured Debt			$ 325
Debt Instrument, Interest Rate, Stated Percentage	5.40%	4.45%	8.875%
Debt Instrument, Face Amount	$ 375	$ 400
Long-term Debt, Other Disclosures [Abstract]
Additional Interest Rate Accrued For Default Of Registration Rights Agreements First Period		0.25%
Additional Interest Rate Accrued For Default Of Registration Rights Agreements Each Subsequent Period		0.25%
Maximum Additional Interest Rate Accrued For Default Of Registration Rights Agreements All Periods		0.50%

XML

Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2012

Derivative Instruments [Abstract]

Notional quantities of the net long (short) positions in commodity derivatives portfolio

		Unit of	Central Hub
Derivative Notional Volumes		Measure	Risk	Basis Risk
Designated as Hedging Instruments
	Williams Partners	Barrels	(1,770,000)
	Williams Partners	MMBtu	7,810,800	6,504,400
Not Designated as Hedging Instruments
	Williams Partners	Barrels	115,000	255,000
	Midstream Canada & Olefins	Barrels	(220,000)

Pre-tax gains and losses for energy commodity derivatives designated as cash flow hedges, as recognized in accumulated other comprehensive income (loss) (AOCI), revenues or costs and operating expense

	Discontinued Operations
			Three months ended		Six months ended
			June 30, 2011		June 30, 2011		Classification
			(Millions)
Designated as cash flow hedges
							Accumulated other
	Net gain (loss) recognized in other comprehensive						comprehensive
		income (loss) (effective portion)	$	79	$	58	income (loss) (AOCI)
	Net gain (loss) reclassified from accumulated other						Income (loss) from
		comprehensive income (loss) into income					discontinued
		(effective portion)	$	67	$	142	operations
							Income (loss) from
							discontinued
	Gain (loss) recognized in income (ineffective portion)		$	-	$	-	operations
Not designated as cash flow hedges
							Income (loss) from
							discontinued
	Gain (loss) recognized in income		$	3	$	6	operations

			Three months ended June 30,				Six months ended June 30,
		2012		2011		2012		2011		Classification
			(Millions)				(Millions)
Net gain (loss) recognized in other comprehensive
	income (loss) (effective portion)	$	55	$	(4)	$	46	$	(6)	AOCI
Net gain (loss) reclassified from accumulated
	other comprehensive income (loss) into									Revenues or Costs and
	income (effective portion)	$	8	$	(4)	$	6	$	(4)	Operating Expenses

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Segment Disclosures (Tables)

6 Months Ended

Jun. 30, 2012

Segment Disclosures [Abstract]

Reconciliation of segment revenues and segment profit (loss) and total assets by reporting segment

					Midstream
			Williams		Canada &
			Partners		Olefins		Other		Eliminations		Total
			(Millions)
Three months ended June 30, 2012
Segment revenues:
	External	$	1,573	$	269	$	4	$	-	$	1,846
	Internal		10		2		3		(15)		-
Total revenues		$	1,583	$	271	$	7	$	(15)	$	1,846
Segment profit (loss)		$	339	$	68	$	1	$	-	$	408
Less:
	Equity earnings (losses)		27		-		-		-		27
	Income (loss) from investments		-		(1)		-		-		(1)
Segment operating income (loss)		$	312	$	69	$	1	$	-		382
General corporate expenses											(50)
Total operating income (loss)										$	332
Three months ended June 30, 2011
Segment revenues:
	External	$	1,636	$	345	$	3	$	-	$	1,984
	Internal		35		2		4		(41)		-
Total revenues		$	1,671	$	347	$	7	$	(41)	$	1,984
Segment profit (loss)		$	471	$	72	$	2	$	-	$	545
Less:
	Equity earnings (losses)		36		-		4		-		40
Segment operating income (loss)		$	435	$	72	$	(2)	$	-		505
General corporate expenses											(45)
Total operating income (loss)										$	460
Six months ended June 30, 2012
Segment revenues:
	External	$	3,246	$	612	$	7	$	-	$	3,865
	Internal		22		4		6		(32)		-
Total revenues		$	3,268	$	616	$	13	$	(32)	$	3,865
Segment profit (loss)		$	827	$	171	$	60	$	-	$	1,058
Less:
	Equity earnings (losses)		57		-		1		-		58
	Income (loss) from investments		-		(2)		53		-		51
Segment operating income (loss)		$	770	$	173	$	6	$	-		949
General corporate expenses											(90)
Total operating income (loss)										$	859
Six months ended June 30, 2011
Segment revenues:
	External	$	3,188	$	660	$	7	$	-	$	3,855
	Internal		62		3		6		(71)		-
Total revenues		$	3,250	$	663	$	13	$	(71)	$	3,855
Segment profit (loss)		$	908	$	146	$	22	$	-	$	1,076
Less:
	Equity earnings (losses)		61		-		13		-		74
	Income (loss) from investments		-		-		11		-		11
Segment operating income (loss)		$	847	$	146	$	(2)	$	-		991
General corporate expenses											(92)
Total operating income (loss)										$	899
June 30, 2012
Total assets (a)		$	18,040	$	1,262	$	1,303	$	(338)	$	20,267
December 31, 2011
Total assets		$	14,380	$	1,138	$	1,275	$	(291)	$	16,502

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Consolidated Statement of Cash Flows (Unaudited) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
OPERATING ACTIVITIES:
Net income (loss)	$ 660	$ 681
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation, depletion and amortization	349	784
Provision (benefit) for deferred income taxes	117	87
Provision for loss on investments, property and other assets	0	51
Net (gain) loss on dispositions of assets	(61)	(6)
Gain on reconsolidation of Wilpro entities (Note 3)	(144)	0
Amortization of stock-based awards	18	25
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	88	(56)
Inventories	10	20
Margin deposits and customer margin deposits payable	26	(30)
Other current assets and deferred charges	39	(9)
Accounts payable	(174)	109
Accrued liabilities	(41)	30
Other, including changes in noncurrent assets and liabilities	(29)	(2)
Net cash provided (used) by operating activities	858	1,684
FINANCING ACTIVITIES:
Proceeds from long-term debt	500	425
Payments of long-term debt	(180)	(225)
Proceeds from issuance of common stock	928	29
Proceeds from sale of limited partner units of consolidated partnership	1,071	0
Dividends paid	(342)	(191)
Dividends and distributions paid to noncontrolling interests	(152)	(105)
Distributions paid to noncontrolling interests on sale of Wilpro assets (Note 3)	(38)	0
Other - net	35	(47)
Net cash provided (used) by financing activities	1,822	(114)
INVESTING ACTIVITIES:
Capital expenditures	(922)	(1,094)
Contributions to equity method investments	(184)	(109)
Purchases of businesses	(2,049)	0
Proceeds from dispositions of investments	78	11
Cash of Wilpro entities upon reconsolidation (Note 3)	121	0
Other - net	66	(7)
Net cash provided (used) by investing activities	(2,890)	(1,199)
Increase (decrease) in cash and cash equivalents	(210)	371
Cash and cash equivalents at beginning of period	889	795
Cash and cash equivalents at end of period	679	1,166
Increases to property, plant and equipment	(999)	(1,086)
Changes in related accounts payable and accrued liabilities	77	(8)
Capital expenditures	$ (922)	$ (1,094)

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General, Description of Business, and Basis of Presentation (Details) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended	12 Months Ended				6 Months Ended		1 Months Ended	3 Months Ended	4 Months Ended	6 Months Ended
	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2012 Gulfstar One	Jun. 30, 2012 Gulfstar One Maximum [Member]	Jun. 30, 2012 Gulfstream Natural Gas System, L.L.C. [Member]	Jun. 30, 2012 Transcontinental Gas Pipe Line Company, LLC [Member]	Jun. 30, 2012 Northwest Pipeline GP [Member]	Apr. 30, 2012 Willams Partners L.P. [Member]	Mar. 31, 2012 Willams Partners L.P. [Member]	Apr. 27, 2012 Willams Partners L.P. [Member]	Jun. 30, 2012 Willams Partners L.P. [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Subsidiary, ownership percentage						100.00%	100.00%
Sale of Stock, Number of Shares Issued in Transaction								10,973,368	8,050,000	16,360,133
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares									7,531,381	11,779,296
Master limited partnership, ownership percentage											68.00%
Noncontrolling Interest Increase From Stock Issuance And Business Combination	$ 1,382
Adjustments to Additional Paid in Capital, Reallocation of Noncontrolling Interest	460
Increase To Deferred Tax Due To Consolidation Less Than Wholly Owned Subsidiary Parent Ownership Interest Changes Issuance Of Equity By Subsidiary To Noncontrolling Interests	273
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage					50.00%
Former business, ownership interest		100.00%
Spinoff Shares Conversion Ratio		0.33
Variable Interest Entity [Line Items]
Carrying value of construction work in process			305
Carrying value of deferred revenue			110
Estimated remaining construction costs				$ 650

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Employee Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pension Benefits
Components of net periodic benefit expense
Service cost	$ 9	$ 10	$ 19	$ 20
Interest cost	14	15	28	32
Expected return on plan assets	(16)	(19)	(32)	(38)
Amortization of prior service cost (credit)	0	0	0	0
Amortization of net actuarial loss	14	10	27	19
Net actuarial loss from settlements	2	0	2	0
Net periodic benefit expense	23	16	44	33
Employee Benefit Plans (Textuals) [Abstract]
Employer contributions under plan			38
Additional contributions to plans anticipated for remainder of 2012	41		41
Other Postretirement Benefits
Components of net periodic benefit expense
Service cost	0	0	1	1
Interest cost	3	3	6	7
Expected return on plan assets	(2)	(2)	(4)	(5)
Amortization of prior service cost (credit)	(1)	(2)	(3)	(5)
Amortization of net actuarial loss	1	1	4	2
Amortization of regulatory asset	0	0	0	0
Net periodic benefit expense	1	0	4	0
Employee Benefit Plans (Textuals) [Abstract]
Employer contributions under plan			7
Additional contributions to plans anticipated for remainder of 2012	$ 8		$ 8

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Segment Disclosures (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011	Jun. 30, 2012		Jun. 30, 2011	Dec. 31, 2011
Segment revenues:
Segment revenues, External	$ 1,846		$ 1,984	$ 3,865		$ 3,855
Segment revenues, Internal	0		0	0		0
Total revenues	1,846		1,984	3,865		3,855
Segment profit (loss)	408		545	1,058		1,076
Less: Equity earnings (losses)	27		40	58		74
Less: Income (loss) from investments	(1)		0	51		11
Total operating income (loss)	332		460	859		899
Total assets by reporting segment
Total assets	20,267			20,267			16,502
Operating Segments [Member]
Segment revenues:
Total operating income (loss)	382		505	949		991
Williams Partners [Member]
Segment revenues:
Segment revenues, External	1,573		1,636	3,246		3,188
Segment revenues, Internal	10		35	22		62
Total revenues	1,583		1,671	3,268		3,250
Segment profit (loss)	339		471	827		908
Less: Equity earnings (losses)	27		36	57		61
Less: Income (loss) from investments	0		0	0		0
Total operating income (loss)	312		435	770		847
Total assets by reporting segment
Total assets	18,040	[1]		18,040	[1]		14,380
Midstream Canada & Olefins [Member]
Segment revenues:
Segment revenues, External	269		345	612		660
Segment revenues, Internal	2		2	4		3
Total revenues	271		347	616		663
Segment profit (loss)	68		72	171		146
Less: Equity earnings (losses)	0		0	0		0
Less: Income (loss) from investments	(1)		0	(2)		0
Total operating income (loss)	69		72	173		146
Total assets by reporting segment
Total assets	1,262			1,262			1,138
Other [Member]
Segment revenues:
Segment revenues, External	4		3	7		7
Segment revenues, Internal	3		4	6		6
Total revenues	7		7	13		13
Segment profit (loss)	1		2	60		22
Less: Equity earnings (losses)	0		4	1		13
Less: Income (loss) from investments	0		0	53		11
Total operating income (loss)	1		(2)	6		(2)
Total assets by reporting segment
Total assets	1,303			1,303			1,275
Business Intersegment Eliminations
Segment revenues:
Segment revenues, External	0		0	0		0
Segment revenues, Internal	(15)		(41)	(32)		(71)
Total revenues	(15)		(41)	(32)		(71)
Segment profit (loss)	0		0	0		0
Less: Equity earnings (losses)	0		0	0		0
Less: Income (loss) from investments	0		0	0		0
Total assets by reporting segment
Total assets	(338)			(338)			(291)
General Corporate Expense [Member]
Segment revenues:
Total operating income (loss)	$ (50)		$ (45)	$ (90)		$ (92)

[1] The increase in Williams Partners’ total assets as compared to the prior year-end is substantially due to the acquisition of certain entities from Delphi Midstream Partners, LLC in the first quarter of 2012 and the acquisition of Caiman Eastern Midstream, LLC in the second quarter of 2012. (See Note 2.

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Consolidated Statement of Income (Unaudited) (USD $) In Millions, except Share data in Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Revenues:
Total revenues	$ 1,846	$ 1,984	$ 3,865	$ 3,855
Segment costs and expenses:
Costs and operating expenses	1,350	1,398	2,701	2,709
Selling, general, and administrative expenses	105	78	198	158
Other (income) expense - net	9	3	17	(3)
Total segment costs and expenses	1,464	1,479	2,916	2,864
General corporate expenses	50	45	90	92
Operating income (loss):
Total operating income (loss)	332	460	859	899
Interest accrued	(140)	(155)	(281)	(311)
Interest capitalized	12	5	22	10
Investing Income - net	30	40	130	84
Other income (expense) - net	3	(2)	(1)	4
Income (loss) from continuing operations before income taxes	237	348	729	686
Provision (benefit) for income taxes	71	109	204	87
Income (loss) from continuing operations	166	239	525	599
Income (loss) from discontinued operations	(1)	58	135	82
Net income (loss)	165	297	660	681
Less: Net income attributable to noncontrolling interests	33	70	105	133
Net income (loss) attributable to The Williams Companies, Inc.	132	227	555	548
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations	133	171	420	471
Income (loss) from discontinued operations	(1)	56	135	77
Net income (loss)	132	227	555	548
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$ 0.21	$ 0.29	$ 0.69	$ 0.80
Income (loss) from discontinued operations	$ 0	$ 0.10	$ 0.22	$ 0.13
Net income (loss)	$ 0.21	$ 0.39	$ 0.91	$ 0.93
Weighted-average shares (thousands)	621,483	588,310	607,357	587,641
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$ 0.21	$ 0.29	$ 0.68	$ 0.79
Income (loss) from discontinued operations	$ 0	$ 0.09	$ 0.22	$ 0.13
Net income (loss)	$ 0.21	$ 0.38	$ 0.90	$ 0.92
Weighted-average shares (thousands)	626,620	597,633	613,570	597,097
Cash dividends declared per common share	$ 0.300	$ 0.200	$ 0.55875	$ 0.325
Williams Partners [Member]
Revenues:
Total revenues	1,583	1,671	3,268	3,250
Operating income (loss):
Total operating income (loss)	312	435	770	847
Midstream Canada & Olefins [Member]
Revenues:
Total revenues	271	347	616	663
Operating income (loss):
Total operating income (loss)	69	72	173	146
Other [Member]
Revenues:
Total revenues	7	7	13	13
Operating income (loss):
Total operating income (loss)	1	(2)	6	(2)
Intercompany Eliminations [Member]
Revenues:
Total revenues	(15)	(41)	(32)	(71)
General Corporate Expense [Member]
Operating income (loss):
Total operating income (loss)	$ (50)	$ (45)	$ (90)	$ (92)

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Stockholders' Equity (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	1 Months Ended	6 Months Ended
	Apr. 30, 2012	Jun. 30, 2012	Jun. 30, 2011
Stockholders Equity Details [Abstract]
Stock Issued During Period, Shares, New Issues	30
Stock Issued During Period Price Per Share	$ 30.59
Proceeds from issuance of common stock	$ 887	$ 928	$ 29

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Consolidated Balance Sheet (Unaudited) (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Stockholders' equity:
Common stock, par value	$ 1	$ 1
Common stock, shares authorized	960	960
Common stock, shares issued	661	626
Treasury stock, at cost	35	35

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Discontinued Operations (Details Textual) (USD $) In Millions, unless otherwise specified	3 Months Ended			6 Months Ended
	Jun. 30, 2012	Mar. 31, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Former Business Ownership Interest						100.00%
Gain On Reconsolidation	$ 0		$ 0	$ 144	$ 0
Notes Receivable, Fair Value Disclosure		88
Fair Value Inputs Discount Rate		12.00%
Maximum [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Fair Value Inputs Probablity Of Default		100.00%
Minimum [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Fair Value Inputs Probablity Of Default		15.00%
Former Venezuela Operations [Memeber]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash Payments Received Related To Former Venezuela Operations Settlement		98
Cash Installments Related to Former Venezuela Operations Settlement		$ 15

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Segment Disclosures

6 Months Ended

Jun. 30, 2012

Segment Disclosures [Abstract]

Segment Disclosures

Note 14. Segment Disclosures

Our reporting segments are Williams Partners and Midstream Canada & Olefins. All remaining business activities are included in Other. (See Note 1.)

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

As discussed in Notes 1 and 3, our former exploration and production business was spun-off on December 31, 2011 and has been reported as discontinued operations in all prior periods presented. Revenues derived from intercompany sales to our former exploration and production business, previously reported as internal, have been recast and are now shown as external. These sales were $78 million and $152 million for the three months and six months ended June 30, 2011, respectively. In addition, costs attributable to activities with our former exploration and production business, previously reported as internal, have been recast and are now shown as external. Such costs were $219 million and $429 millionfor the three monthsand six months ended June 30, 2011, respectively.

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 Income and total assets by reporting segment.

					Midstream
			Williams		Canada &
			Partners		Olefins		Other		Eliminations		Total
			(Millions)
Three months ended June 30, 2012
Segment revenues:
	External	$	1,573	$	269	$	4	$	-	$	1,846
	Internal		10		2		3		(15)		-
Total revenues		$	1,583	$	271	$	7	$	(15)	$	1,846
Segment profit (loss)		$	339	$	68	$	1	$	-	$	408
Less:
	Equity earnings (losses)		27		-		-		-		27
	Income (loss) from investments		-		(1)		-		-		(1)
Segment operating income (loss)		$	312	$	69	$	1	$	-		382
General corporate expenses											(50)
Total operating income (loss)										$	332
Three months ended June 30, 2011
Segment revenues:
	External	$	1,636	$	345	$	3	$	-	$	1,984
	Internal		35		2		4		(41)		-
Total revenues		$	1,671	$	347	$	7	$	(41)	$	1,984
Segment profit (loss)		$	471	$	72	$	2	$	-	$	545
Less:
	Equity earnings (losses)		36		-		4		-		40
Segment operating income (loss)		$	435	$	72	$	(2)	$	-		505
General corporate expenses											(45)
Total operating income (loss)										$	460
Six months ended June 30, 2012
Segment revenues:
	External	$	3,246	$	612	$	7	$	-	$	3,865
	Internal		22		4		6		(32)		-
Total revenues		$	3,268	$	616	$	13	$	(32)	$	3,865
Segment profit (loss)		$	827	$	171	$	60	$	-	$	1,058
Less:
	Equity earnings (losses)		57		-		1		-		58
	Income (loss) from investments		-		(2)		53		-		51
Segment operating income (loss)		$	770	$	173	$	6	$	-		949
General corporate expenses											(90)
Total operating income (loss)										$	859
Six months ended June 30, 2011
Segment revenues:
	External	$	3,188	$	660	$	7	$	-	$	3,855
	Internal		62		3		6		(71)		-
Total revenues		$	3,250	$	663	$	13	$	(71)	$	3,855
Segment profit (loss)		$	908	$	146	$	22	$	-	$	1,076
Less:
	Equity earnings (losses)		61		-		13		-		74
	Income (loss) from investments		-		-		11		-		11
Segment operating income (loss)		$	847	$	146	$	(2)	$	-		991
General corporate expenses											(92)
Total operating income (loss)										$	899
June 30, 2012
Total assets (a)		$	18,040	$	1,262	$	1,303	$	(338)	$	20,267
December 31, 2011
Total assets		$	14,380	$	1,138	$	1,275	$	(291)	$	16,502

_______

(a)The increase in Williams Partners' total assets as compared to the prior year-end is substantially due to the acquisition of certain entities from Delphi Midstream Partners, LLC in the first quarter of 2012 and the acquisition of Caiman Eastern Midstream, LLC in the second quarter of 2012. (See Note 2.)

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Asset Sales and Other Accruals (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Component of Operating Other Cost and Expense [Line Items]
Other (income) expense - net	$ 9	$ 3	$ 17	$ (3)
Williams Partners [Member] | Capitalization of project feasibility costs previously expensed [Member]
Component of Operating Other Cost and Expense [Line Items]
Other (income) expense - net				$ (10)

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Discontinued Operations (Tables)

6 Months Ended

Jun. 30, 2012

Discontinued Operations [Abstract]

Summarized Results of Discontinued Operations

Summarized Results of Discontinued Operations
		Three months ended				Six months ended
		June 30,				June 30,
		2012		2011		2012		2011
		(Millions)
Revenues		$	-	$	985	$	-	$	1,977
Income (loss) from discontinued operations before gain on
	reconsolidation, impairment and income taxes	$	(2)	$	97	$	(10)	$	143
Gain on reconsolidation			-		-		144		-
Impairment			-		(2)		-		(11)
(Provision) benefit for income taxes			1		(37)		1		(50)
	Income (loss) from discontinued operations	$	(1)	$	58	$	135	$	82
Income (loss) from discontinued operations:
	Attributable to noncontrolling interests	$	-	$	2	$	-	$	5
	Attributable to The Williams Companies, Inc.	$	(1)	$	56	$	135	$	77

Pre-tax gains and losses for energy commodity derivatives designated as cash flow hedges, as recognized in accumulated other comprehensive income (loss) (AOCI), revenues or costs and operating expense

	Discontinued Operations
			Three months ended		Six months ended
			June 30, 2011		June 30, 2011		Classification
			(Millions)
Designated as cash flow hedges
							Accumulated other
	Net gain (loss) recognized in other comprehensive						comprehensive
		income (loss) (effective portion)	$	79	$	58	income (loss) (AOCI)
	Net gain (loss) reclassified from accumulated other						Income (loss) from
		comprehensive income (loss) into income					discontinued
		(effective portion)	$	67	$	142	operations
							Income (loss) from
							discontinued
	Gain (loss) recognized in income (ineffective portion)		$	-	$	-	operations
Not designated as cash flow hedges
							Income (loss) from
							discontinued
	Gain (loss) recognized in income		$	3	$	6	operations

			Three months ended June 30,				Six months ended June 30,
		2012		2011		2012		2011		Classification
			(Millions)				(Millions)
Net gain (loss) recognized in other comprehensive
	income (loss) (effective portion)	$	55	$	(4)	$	46	$	(6)	AOCI
Net gain (loss) reclassified from accumulated
	other comprehensive income (loss) into									Revenues or Costs and
	income (effective portion)	$	8	$	(4)	$	6	$	(4)	Operating Expenses

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Consolidated Statement of Changes in Equity (Unaudited) (USD $) In Millions	Total	Common Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Treasury Stock	Total Stockholders' Equity	Noncontrolling Interests [Member]
Beginning balance at Dec. 31, 2011	$ 2,586	$ 626	$ 7,920	$ (5,820)	$ (389)	$ (1,041)	$ 1,296	$ 1,290
Net income (loss)	660	0	0	555	0	0	555	105
Other Comprehensive Income (Loss), Net of Tax	44	0	0	0	32	0	32	12
Cash dividends - common stock	(342)	0	0	(342)	0	0	(342)	0
Dividends and distributions to noncontrolling interests	(190)	0	0	0	0	0	0	(190)
Issuance of common stock from debentures conversion	6	1	5	0	0	0	6	0
Stock-based compensation, net of tax	67	5	62	0	0	0	67	0
Sale of limited partner units of consolidated partnership	1,071	0	0	0	0	0	0	1,071
Issuance of limited partner units of Williams Partners L.P. related to acquisitions	1,044	0	0	0	0	0	0	1,044
Changes in Williams Partners L.P. ownership interest	(273)	0	460	0	0	0	460	(733)
Sale of common stock	887	30	857	0	0	0	887	0
Reconsolidation of noncontrolling interest in Wilpro entities (see Note 3)	65	0	0	0	0	0	0	65
Other	2	(1)	1	0	0	0	0	2
Ending balance at Jun. 30, 2012	$ 5,627	$ 661	$ 9,305	$ (5,607)	$ (357)	$ (1,041)	$ 2,961	$ 2,666

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Consolidated Statement of Comprehensive Income (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Comprehensive income (loss):
Net income (loss)	$ 165	$ 297	$ 660	$ 681
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of ($14) and ($12) in 2012 and ($29) and ($21) in 2011	40	46	34	31
Reclassifications into earnings of net derivative instrument (gain) loss, net of taxes of $2 and $2 in 2012 and $25 and $53 in 2011	(5)	(38)	(4)	(85)
Foreign currency translation adjustments	(17)	5	2	27
Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit expense	(1)	(1)	(1)	(1)
Net actuarial gain (loss) arising during the year, net of taxes of $1 and $1 in 2012	(3)	0	(3)	0
Amortization of actuarial (gain) loss included in net periodic benefit expense, net of taxes of ($6) and ($11) in 2012 and ($3) and ($7) in 2011	10	6	19	12
Equity securities:
Unrealized gain (loss) on equity securities, net of taxes of ($1) and ($1) in 2011	0	3	0	3
Reclassifications into earnings of (gain) loss on sale of equity securities, net of taxes of $2 in 2012	0	0	(3)	0
Other comprehensive income (loss)	24	21	44	(13)
Comprehensive income (loss)	189	318	704	668
Less: Comprehensive income (loss) attributable to noncontrolling interest	47	70	117	133
Comprehensive Income (Loss), Net of Tax, Attributable to The Williams Companies, Inc.	$ 142	$ 248	$ 587	$ 535

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Debt and Banking Arrangements

6 Months Ended

Jun. 30, 2012

Debt and Banking Arrangements [Abstract]

Debt and Banking Arrangements

Note 9. Debt and Banking Arrangements

Credit Facilities

Letter of credit capacity under our $900 million and WPZ's $2 billion credit facilities is $700 million and $1.3 billion, respectively.  At June 30, 2012, no letters of credit have been issued on either facility. No loans are outstanding on our credit facility at June 30, 2012. Loans totaling $345 million are outstanding on WPZ's credit facility at June 30, 2012. We have issued letters of credit totaling $24 million as of June 30, 2012, under certain bilateral bank agreements.

Issuances and Retirements

In July 2012, Transco issued $400 million of 4.45 percent senior unsecured notes due 2042 to investors in a private debt placement. A portion of these proceeds was used to repay Transco's $325 million 8.875 percent senior unsecured notesthat matured on July 15, 2012. As a result of this transaction, we presentedthe $325 million notes as long-term debt at June 30, 2012.As part of the new issuance, Transco entered into a registration rights agreement with the initial purchasers of the unsecured notes.  Transco is obligated to file a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 180 days from closing and to use commercially reasonable efforts to cause the registration statement to be declared effective within 270 days after closing and to consummate the exchange offer within 30 business days after such effective date. Transco is required to provide a shelf registration statement to cover resales of the notes under certain circumstances.  If Transco fails to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25percent per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such defaults of 0.5 percent annually.  Following the cure of any registration defaults, the accrual of additional interest will cease.

In August 2011, Transco issued $375 million of 5.4 percent senior unsecured notes due 2041 to investors in a private debt placement.  As part of the new issuance, Transco entered into a registration rights agreement with the initial purchasers of the notes.  An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in February 2012 and completed in March 2012.

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Document and Entity Information	6 Months Ended
	Jun. 30, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	Williams Companies Inc
Entity Central Index Key	0000107263
Document Type	10-Q
Document Period End Date	Jun. 30, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	626,467,362

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Stockholders' Equity

6 Months Ended

Jun. 30, 2012

Stockholders' Equity [Abstract]

Stockholders' Equity [Text Block]

Note 10. Stockholders' Equity

In April 2012, we issued 30 million shares of common stock in a public offering at a price of $30.59 per share. We used the net proceeds of $887 million to fund a portion of the purchase of additional WPZ common units in connection with WPZ's Caiman Acquisition. (See Note 2.)

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Consolidated Statement of Comprehensive Income (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax Effect [Abstract]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ (14)	$ (29)	$ (12)	$ (21)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Tax	2	25	2	53
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax	1	0	1	0
Other Comprehensive Income (Loss), Reclassification Of Defined Benefit Plans Net Gain (Loss) Recognized In Net Periodic Benefit Cost Tax Effect	(6)	(3)	(11)	(7)
Other Comprehensive Income (Loss), Available-for-sale Securities, Tax [Abstract]
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	0	(1)	0	(1)
Other Comprehensive Income (Loss), Reclassification Adjustment for Sale of Securities Included in Net Income, Tax	$ 0	$ 0	$ 2	$ 0

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Asset Sales and Other Accruals

6 Months Ended

Jun. 30, 2012

Asset Sales and Other Accruals [Abstract]

Asset Sales and Other Accruals

Note 4. Asset Sales and Other Accruals

Other (income) expense – net within segment costs and expenses in the six months ended June 30, 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. This reversal was made upon determining that the related project was probable of development. These costs are now included in the capital costs of the project, which we believe are probable of recovery through the project rates.

Investing income – netat Other includesincome of $63 million and $11 million in the six months ended June 30, 2012 and 2011, respectively, related to the 2010 sale of our interest in Accroven SRL. As part of a settlement regarding certain Venezuelan assets in the first quarter of 2012 (see Note 3), we also received payment for all outstanding balances due from this sale, including interest. Payments were recognized upon receipt, as future collections were not reasonably assured.

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Discontinued Operations

6 Months Ended

Jun. 30, 2012

Discontinued Operations [Abstract]

Discontinued Operations

Note 3. Discontinued Operations

On December 31, 2011, we completed the tax-free spin-off of our 100 percent interest in WPX to our shareholders. At December 31, 2011, the net assets of our former exploration and production business were eliminated from our consolidated balance sheet as the spin-off was complete.

The following summarized results of discontinued operations for 2011 reflect the results of operations of our former exploration and production business as discontinued operations.The summarized results of discontinued operations for 2012primarily include a gain on reconsolidation following the sale of certain of our former Venezuela operations, whose facilities were expropriated by the Venezuelan government in May 2009.

Summarized Results of Discontinued Operations
		Three months ended				Six months ended
		June 30,				June 30,
		2012		2011		2012		2011
		(Millions)
Revenues		$	-	$	985	$	-	$	1,977
Income (loss) from discontinued operations before gain on
	reconsolidation, impairment and income taxes	$	(2)	$	97	$	(10)	$	143
Gain on reconsolidation			-		-		144		-
Impairment			-		(2)		-		(11)
(Provision) benefit for income taxes			1		(37)		1		(50)
	Income (loss) from discontinued operations	$	(1)	$	58	$	135	$	82
Income (loss) from discontinued operations:
	Attributable to noncontrolling interests	$	-	$	2	$	-	$	5
	Attributable to The Williams Companies, Inc.	$	(1)	$	56	$	135	$	77

Gain on reconsolidation for 2012 is related to our majority ownership in entities (the Wilpro entities) that owned and operated the El Furrial and PIGAP II gas compression facilities prior to their expropriation by the Venezuelan government in May 2009.  We deconsolidated the Wilpro entities in 2009.  In the first quarter of 2012, the El Furrial and PIGAP II assets were sold as part of a settlement related to the 2009 expropriation of these assets.  Upon closing, the lenders that had provided financing for these operations were repaid in full, and the Wilpro entities received $98 million in cash and the right to receivequarterly cash installments of $15 million (note receivable) through the first quarter of 2016 plus interest.  Following the settlement and repayment in full of the lenders, we reestablished control and, therefore, reconsolidated the Wilpro entities and recognized a gain on reconsolidation of $144 million. This gain reflects our share of the cash, including cash received in the settlement, and a note receivable held by the Wilpro entities at the time of reconsolidation.  The note receivable was recognized at its estimated fair value, as further described below. 

To determine the fair value of the note receivable at the time of reconsolidation, we considered both quantitative (income) and qualitative (market) approaches. Under our quantitative approach, we calculated the net present value of a probability-weighted set of cash flows utilizing assumptions based on contractual terms, historical payment patterns by the counterparty under similar circumstances, our likelihood of using arbitration if the counterparty does not perform, and discount rates. Our qualitative analysis utilized information as to how similar notes might be valued. This analysis also reduced the value due to its limited marketability as the payment terms are embedded within the overall settlement agreement. Both analyses resulted in similar fair values. Ultimately we determined the fair value of the note receivable to be $88 million at the time of reconsolidation, utilizing a probability-weighted cash flow analysis with a discount rate of approximately 12 percent and a probability of default ranging from 15 percent to 100 percent. Utilizing different assumptions regarding the collectability of the note receivable and discount rates could result in a materially different fair value.See Note 11 for a further discussion of this note receivable.

Revenues andincome (loss) from discontinued operations before gain on reconsolidation, impairment and income taxes for 2011 primarily reflects the results of operations of our discontinued exploration and production business.

Energy Commodity Derivatives Gains and Losses

The following table presents pre-tax gains and losses for the three months and six months ended June 30, 2011,for our former exploration and production business' energy commodity derivatives.

			Three months ended		Six months ended
			June 30, 2011		June 30, 2011		Classification
			(Millions)
Designated as cash flow hedges
							Accumulated other
	Net gain (loss) recognized in other comprehensive						comprehensive
		income (loss) (effective portion)	$	79	$	58	income (loss) (AOCI)
	Net gain (loss) reclassified from accumulated other						Income (loss) from
		comprehensive income (loss) into income					discontinued
		(effective portion)	$	67	$	142	operations
							Income (loss) from
							discontinued
	Gain (loss) recognized in income (ineffective portion)		$	-	$	-	operations
Not designated as cash flow hedges
							Income (loss) from
							discontinued
	Gain (loss) recognized in income		$	3	$	6	operations

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Acquisitions (Tables)

6 Months Ended

Jun. 30, 2012

Acquisitions [Abstract]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

		Laser		Caiman
Assets held for sale		$	18	$	-
Other current assets			3		13
Property, plant and equipment			158		665
Intangible assets			318		1,313
Current liabilities			(21)		(98)
	Identifiable net assets acquired		476		1,893
Goodwill			290		434
		$	766	$	2,327

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Fair Value Measurements

6 Months Ended

Jun. 30, 2012

Fair Value Measurements [Abstract]

Fair Value Measurements

Note 11. Fair Value Measurements

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivableand accounts payable approximate fair value because of the short-term nature of these instruments.Therefore, these assets and liabilities are not presented in the following table.

								Fair Value Measurements Using
									Quoted
									Prices In
									Active		Significant
									Markets for		Other		Significant
									Identical		Observable		Unobservable
				Carrying		Fair			Assets		Inputs		Inputs
				Amount		Value			(Level 1)		(Level 2)		(Level 3)
				(Millions)
Assets (liabilities) at June 30, 2012:
	Measured on a recurring basis:
		ARO Trust investments		$	25	$	25		$	25	$	-	$	-
		Energy derivatives assets not designated as
			hedging instruments		5		5			2		3		-
		Energy derivatives assets designated as hedging
			instruments		41		41			29		12		-
		Energy derivatives liabilities not designated as
			hedging instruments		(5)		(5)			(3)		(2)		-
	Additional disclosures:
		Notes receivable and other			131		133			6		9		118
		Long-term debt, including current portion (a)			(9,034)		(10,426)			-		(10,426)		-
		Guarantee			(33)		(31)			-		(31)		-
		Customer margin deposits payable			(32)		(32)			(32)		-		-
Assets (liabilities) at December 31, 2011:
	Measured on a recurring basis:
		ARO Trust investments		$	25	$	25		$	25	$	-	$	-
		Available-for-sale equity securities			24		24			24		-		-
		Energy derivatives assets not designated as
			hedging instruments		1		1			1		-		-
	Additional disclosures:
		Notes receivable and other			57		57			N/A		N/A		N/A
		Long-term debt, including current portion (a)			(8,718)		(10,043)			N/A		N/A		N/A
		Guarantee			(34)		(32)			N/A		N/A		N/A
(a) Excludes capital leases

FairValue Methods

We use the following methods and assumptions in estimating the fairvalue of our financial instruments:

Assets and liabilities measured at fair value on a recurring basis

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

Energy derivatives: Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) contracts, which consist solely of swaps that are measured at fair value on a recurring basis.The tenure of our energy derivatives portfolio is relatively short with all of our energy derivatives expiring in the next ninemonths. 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 do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives are reported in other current assets and deferred charges and accrued liabilities in the Consolidated Balance Sheet.

Energy derivatives considered Level 1 measurements consist of New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets.

Energy derivatives included in our Level 2 measurements consist solely of OTC swaps. Swap contracts included in Level 2 are valued using an income approach including present value techniques. Significant inputs into our Level2 valuations include commodity prices 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.

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 transfers between Level 1 and Level 2 occurred during the six months ended June 30, 2012or 2011.

Additional fair value disclosures

Notes receivable and other: Notes receivable and other includesanote receivable related to the sale of certain former Venezuela assets. The disclosed fair value of this note receivable uses an approach and assumptions consistent with that used at initial recognition (see Note 3), updated to consider receipt of the first scheduled payment. The carrying value and disclosed fair value of this note is $75 million and $78 million, respectively, at June 30, 2012. The current and noncurrent portions are reported in accounts and notes receivable and regulatory assets, deferred charges, and other, respectively, in the Consolidated Balance Sheet.

Notes receivable and other, also includesa receivable from our former affiliate, WPX (see Note 13), and other notes receivable.The disclosed fair value of these receivables is determined by an income approach which considers the underlying contract amounts andour assessment of our ability to recover these amounts. The current and noncurrent portions are reported in accounts and notes receivable and regulatory assets, deferred charges, and other, respectively, in the Consolidated Balance Sheet.

Long-term debt:The disclosed fair value of our long-term debt is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.

Guarantee:The guarantee represented in the 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 that extends through 2042.

To estimate the disclosed fair value of the guarantee, an estimated default rate is applied to the sum of the future contractual lease paymentsusing an income approach.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 rate is published by Moody's Investors Service. This guarantee is reported in accrued liabilities in the Consolidated Balance Sheet.

Customer margin deposits payable:The disclosed fair value of our customer margin deposits payable is considered to approximate the carrying value generally due to the short-term nature of these items, and are reported in accrued liabilities in the Consolidated Balance Sheet.

Guarantees

We are required by our revolving credit agreements to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain 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.

Regarding our previously described guarantee of Wiltel's lease performance, the maximum potential exposure is approximately $37million at June 30, 2012 and $38 million at December 31, 2011. Our exposure declines systematically throughout the remaining term of WilTel's obligation.

We have providedguarantees in the event of nonpayment by our previously owned subsidiary, WPX, on certain contracts, primarily including a long-term transportation capacity agreement and a natural gas purchase contract, extending through 2017 and 2023, respectively. We estimate the maximum undiscounted potential future payment obligation under these remaining guarantees is approximately $245 million at June 30, 2012.Our recorded liability for these guarantees, which considers our estimate of the fair value of the guarantees, is insignificant.

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Employee Benefit Plans

6 Months Ended

Jun. 30, 2012

Employee Benefit Plans [Abstract]

Employee Benefit Plans

Note 7. Employee Benefit Plans

Net periodic benefit expense is as follows:

		Pension Benefits
		Three months				Six months
		ended June 30,				ended June 30,
		2012		2011		2012		2011
			(Millions)
Components of net periodic benefit expense:
	Service cost	$	9	$	10	$	19	$	20
	Interest cost		14		15		28		32
	Expected return on plan assets		(16)		(19)		(32)		(38)
	Amortization of net actuarial loss		14		10		27		19
	Net actuarial loss from settlements		2		-		2		-
	Net periodic benefit expense	$	23	$	16	$	44	$	33
		Other Postretirement Benefits
		Three months				Six months
		ended June 30,				ended June 30,
		2012		2011		2012		2011
			(Millions)
Components of net periodic benefit expense:
	Service cost	$	-	$	-	$	1	$	1
	Interest cost		3		3		6		7
	Expected return on plan assets		(2)		(2)		(4)		(5)
	Amortization of prior service cost (credit)		(1)		(2)		(3)		(5)
	Amortization of net actuarial loss		1		1		4		2
	Net periodic benefit expense	$	1	$	-	$	4	$	-

During the six months ended June 30,2012, we contributed $38million to our pension plans and $7million to our other postretirement benefit plans. We presently anticipate makingadditional contributions of approximately $41millionto our pension plans andapproximately $8millionto our other postretirement benefit plans in the remainder of 2012.

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Provision (Benefit) for Income Taxes

6 Months Ended

Jun. 30, 2012

Provision (Benefit) for Income Taxes [Abstract]

Provision (Benefit) for Income Taxes

Note 5. Provision (Benefit) for Income Taxes

The provision (benefit) for income taxes includes:

		Three months ended				Six months ended
		June 30,				June 30,
			2012		2011		2012		2011
			(Millions)				(Millions)
Current:
	Federal	$	33	$	59	$	54	$	88
	State		4		5		8		8
	Foreign		3		14		24		(6)
			40		78		86		90
Deferred:
	Federal		30		25		117		(7)
	State		(3)		2		(6)		(1)
	Foreign		4		4		7		5
			31		31		118		(3)
Total provision (benefit)		$	71	$	109	$	204	$	87

The effective income tax rate for the total provision for the three months ended June 30, 2012 is less than the federal statutory rate primarily due to the impact of nontaxable noncontrolling interests.

The effective income tax rate for the total provision for the six months ended June 30, 2012 is less than the federal statutory rate primarily due to the impact of nontaxable noncontrolling interests and taxes on foreign operations.

The effective income tax rate for the total provision for the three months ended June 30, 2011 is less than the federal statutory rate primarily due to the impact of nontaxable noncontrolling interests and taxes on foreign operations, partially offset by the effect of state income taxes.

The effective income tax rate for the total provision for the six months ended June 30, 2011 is less than the federal statutory rate primarily due to federal settlements, an international revised assessment, and the impact of nontaxable noncontrolling interests and taxes on foreign operations, partially offset by the effect of state income taxes.

During the first quarter of 2011, we finalized settlements for 1997 through 2008 on certain contested matters with the Internal Revenue Service and also received a revised assessment on an international matter. These settlements and revised assessment resulted in atax benefit of approximately $124 millionfor the six months ended June 30, 2011. As a result of these settlements and revised assessment, we decreased our unrecognized tax benefits by approximately $62 million during the first quarter of 2011.

On December 23, 2011, the Internal Revenue Service issued temporary and proposed regulations providing guidance relating to the deduction and capitalization of expenditures made to acquire, produce, or improve tangible property. These regulations, effective January 1, 2012, will generally require changes in accounting methods. Once complete guidance has been released, we will assess the impact of the regulations on our Consolidated Financial Statements.

During the next 12 months, we do not expect ultimate resolution of any unrecognized tax benefit associated with domestic or international matters to have a material impact on our unrecognized tax benefit position.

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Earnings (Loss) Per Common Share from Continuing Operations

6 Months Ended

Jun. 30, 2012

Earnings (Loss) Per Common Share from Continuing Operations [Abstract]

Earnings (Loss) Per Common Share from Continuing Operations

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

		Three months ended				Six months ended
		June 30,				June 30,
		2012		2011		2012		2011
			(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	$	133	$	171	$	420	$	471
Basic weighted-average shares			621,483		588,310		607,357		587,641
Effect of dilutive securities:
	Nonvested restricted stock units		2,109		3,887		2,836		4,005
	Stock options		2,614		3,537		2,776		3,501
	Convertible debentures		414		1,899		601		1,950
Diluted weighted-average shares			626,620		597,633		613,570		597,097
Earnings (loss) per common share from continuing operations:
	Basic	$	.21	$	.29	$	.69	$	.80
	Diluted	$	.21	$	.29	$	.68	$	.79

Effective January 1, 2012, new awards of time-based restricted stock units contain a nonforfeitable right to dividends during the vesting period. These share-based payment awards are participating securities and are included in the computation of earnings (loss) per common share pursuant to the two-class method. The impact for the three and six months ended June 30, 2012,is immaterial.

The table below includes information related to stock options that were outstanding at June 30 of each respective year but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the second quarter weighted-average market price of our common shares.

	June 30,
	2012	2011
Options excluded (millions)	-	1.0
Weighted-average exercise price of options excluded	N/A	$36.47
Exercise price ranges of options excluded	N/A	$32.05 - $37.88
Second quarter weighted-average market price	$30.93	$30.54

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Inventories

6 Months Ended

Jun. 30, 2012

Inventory [Abstract]

Inventories

Note 8. Inventories

	June 30,		December 31,
	2012		2011
		(Millions)
Natural gas liquids, olefins, and natural gas in underground storage	$	86	$	98
Materials, supplies, and other		73		71
	$	159	$	169

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Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Summarized Results of Discontinued Operations
Revenues	$ 0	$ 985	$ 0	$ 1,977
Income (loss) from discontinued operations before gain on reconsolidation, impairment and income taxes	(2)	97	(10)	143
Gain On Reconsolidation	0	0	144	0
Impairment	0	(2)	0	(11)
(Provision) benefit for income taxes	1	(37)	1	(50)
Income (loss) from discontinued operations	(1)	58	135	82
Income (loss) from discontinued operations
Attributable to noncontrolling interests	0	2	0	5
Attributable to The Williams Companies, Inc.	(1)	56	135	77
Pre Tax Gains And Losses For Energy Derivatives Designated As Cash Flow Hedges [Abstract]
Net gain (loss) recognized in other comprehensive income (loss) (effective portion)	55	(4)	46	(6)
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion)	8	(4)	6	(4)
Segment, Discontinued Operations [Member]
Pre Tax Gains And Losses For Energy Derivatives Designated As Cash Flow Hedges [Abstract]
Net gain (loss) recognized in other comprehensive income (loss) (effective portion)		79		58
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion)		67		142
Gain (loss) recognized in income (ineffective portion)		0		0
Pre Tax Gains And Losses For Energy Derivatives Not Designated As Cash Flow Hedges [Abstract]
Gain (loss) recognized in income		$ 3		$ 6

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Derivative Instruments (Details Textual) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Dec. 31, 2011
Derivative Instruments [Abstract]
Collateral totaling of credit risk	$ 0	$ 0
Maximum period hedged in cash flow hedge (Years)	0.5
Net gains (losses) of cash flow hedge to be reclassified into earnings within next year	40
Gain (Loss) on Cash Flow Hedge Ineffectiveness, Net	0
Gain (Loss) from Components Excluded from Assessment of Cash Flow Hedge Effectiveness, Net	0
Gain (Loss) on Discontinuation of Cash Flow Hedges	$ 0

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Contingent Liabilities

6 Months Ended

Jun. 30, 2012

Contingent Liabilities [Abstract]

Contingent Liabilities

Note 13. Contingent Liabilities

Indemnification of WPX Matters

We have agreed to indemnify our former affiliate, WPX and its subsidiaries, related to the following matters. In connection with this indemnification, we have retained applicable accrued asset and liability balances associated with these matters, and as a result, have an indirect exposure to future developments in these matters.

Issues resulting from California energy crisis

WPX's former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by WPX 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). WPX has 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.

Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, WPX continues to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. WPX is 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 WPX's collection of accrued interest from counterparties as well as their payment of accrued interest on refund amounts. Thus, as currently contemplated by the parties, the settlement agreement would resolve most, if not all, of WPX's legal issues arising from the 2000-2001 California Energy Crisis.We currently have a net receivable from WPX related to these matters.

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 WPX and others, in each case seeking an unspecified amount of damages. WPX is 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 thefederal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of WPX and most of the other defendants based on plaintiffs' lack of standing. In 2009, the court denied the plaintiffs' request for reconsideration of the Colorado dismissal and entered judgment in WPX's favor. The court's order became final on July18, 2011, and the Colorado plaintiffs might appeal the order.

In the other cases, on July 18, 2011, the Nevada district court granted WPX's joint motions for summary judgment to preclude the plaintiffs' state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs' class certification motion as moot. In 2011, the plaintiffs' appealed the court's ruling to the Ninth Circuit Court of Appeals, and in early 2012, the parties completed briefing the issues.A decision is expected in 2013. 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 and our related indemnification obligation could result in future charges that may be material to our results of operations.

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 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 accrued 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. As a result, we reduced our accrued liability as of December 31, 2011 by $33 million, including $14 million of interest.The Texas Court of Appeals also reversed and remanded the contract claim and attorney fee claims for further proceedings. None of the parties filed a petition for review in the Texas Supreme Court. On May 8, 2012, the Texas Court of Appeals issued its mandate remanding the case to the trial court.

Alaska refinery contamination litigation

In January 2010, James West filed a class action lawsuit in state court in Fairbanks, Alaska on behalf of individual property owners whose water contained sulfolane contamination allegedly emanating from the Flint Hills Oil Refinery in North Pole, Alaska. The suit named our subsidiary, Williams Alaska Petroleum Inc. (WAPI),and Flint Hills Resources Alaska, LLC (FHRA),a subsidiary of Koch Industries, Inc.,as defendants. We owned and operated the refinery until 2004 when we sold it to FHRA. We and FHRA have made claims under the pollution liability insurance policy issued in connection with the sale of the North Pole refinery to FHRA.We and FHRA also filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination.

In August 2010, the court denied West's request for class certification. On May 5, 2011, we and FHRA settled the James West claim, leaving FHRA and WAPI claims. On November 17, 2011, we filed motions for summary judgment on FHRA's claims against us, but the motions are unlikely to resolve all the outstanding claims. Similarly, FHRA has filed motions for summary judgment that would resolve some, but not all, of our claims against it. Trial is set for April 2013.

While significant uncertainty still exists due to, among other things, ongoing proceedings and expert evaluations, we currently estimate that our reasonably possible loss exposure in this matter could range from an insignificant amount up to $32 million. We might have the ability to recover any such losses under the pollution liability policy if FHRA has not exhausted the policy limits.

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.

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. 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. As of June 30, 2012, we have accrued liabilities totaling $45 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered and the final cleanup standards mandated by the EPA and other governmental authorities.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules.  More recent 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.

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 haveinvolved the EPA, various state environmental authorities and identification as a potentially responsible party at various Superfund waste disposal sites.At June 30, 2012, we have accrued liabilities of $9million 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 June 30, 2012, we have accrued liabilities totaling $8 million for these costs.

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;
• Former petroleum refining facilities;
• Former exploration and production and mining operations;
• Former electricity and natural gas marketing and trading operations.

At June 30, 2012, we have accrued environmental liabilities of $28 million related to these matters.

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 June 30, 2012, other than as previously disclosed, we are not aware of any material claims involving the indemnities;thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future 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

We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.

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Earnings (Loss) Per Common Share from Continuing Operations (Tables)

6 Months Ended

Jun. 30, 2012

Earnings (Loss) Per Common Share from Continuing Operations [Abstract]

Earnings (loss) per common share from continuing operations

		Three months ended				Six months ended
		June 30,				June 30,
		2012		2011		2012		2011
			(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	$	133	$	171	$	420	$	471
Basic weighted-average shares			621,483		588,310		607,357		587,641
Effect of dilutive securities:
	Nonvested restricted stock units		2,109		3,887		2,836		4,005
	Stock options		2,614		3,537		2,776		3,501
	Convertible debentures		414		1,899		601		1,950
Diluted weighted-average shares			626,620		597,633		613,570		597,097
Earnings (loss) per common share from continuing operations:
	Basic	$	.21	$	.29	$	.69	$	.80
	Diluted	$	.21	$	.29	$	.68	$	.79

Stock options excluded

	June 30,
	2012	2011
Options excluded (millions)	-	1.0
Weighted-average exercise price of options excluded	N/A	$36.47
Exercise price ranges of options excluded	N/A	$32.05 - $37.88
Second quarter weighted-average market price	$30.93	$30.54

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Derivatives Instruments (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pre-tax gains and losses for energy commodity derivatives designated as cash flow hedges, as recognized in accumulated other comprehensive income (loss) (AOCI), revenues or costs and operating expenses
Net gain (loss) recognized in other comprehensive income (loss) (effective portion)	$ 55	$ (4)	$ 46	$ (6)
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$ 8	$ (4)	$ 6	$ (4)

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Inventories (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Inventories
Natural gas liquids,olefins and natural gas in underground storage	$ 86	$ 98
Materials, supplies, and other	73	71
Inventories, Total	$ 159	$ 169

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Consolidated Balance Sheet (Unaudited) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 679	$ 889
Accounts and notes receivable	636	637
Inventories	159	169
Regulatory assets	41	40
Other current assets and deferred charges	167	159
Total current assets	1,682	1,894
Investments	1,533	1,391
Property, plant, and equipment, at cost	20,835	19,082
Accumulated depreciation and amortization	(6,779)	(6,502)
Property, plant and equipment - net	14,056	12,580
Goodwill	724	0
Other Intangible Assets, Net	1,662	44
Regulatory assets, deferred charges, and other	610	593
Total assets	20,267	16,502
Current liabilities:
Accounts payable	695	691
Accrued liabilities	599	631
Long-term debt due within one year	4	353
Total current liabilities	1,298	1,675
Long-term debt	9,033	8,369
Deferred income taxes	2,555	2,157
Regulatory liabilities, deferred income, and other	1,754	1,715
Contingent liabilities (Note 13)
Stockholders' equity:
Common stock (960 million shares authorized at $1 par value; 661 million shares issued at June 30, 2012 and 626 million shares issued at December 31, 2011)	661	626
Capital in excess of par value	9,305	7,920
Retained deficit	(5,607)	(5,820)
Accumulated other comprehensive income (loss)	(357)	(389)
Treasury stock, at cost (35 million shares of common stock)	(1,041)	(1,041)
Total stockholders' equity	2,961	1,296
Noncontrolling interests in consolidated subsidiaries	2,666	1,290
Total equity	5,627	2,586
Total liabilities and equity	$ 20,267	$ 16,502

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Acquisitions

6 Months Ended

Jun. 30, 2012

Acquisitions [Abstract]

Acquisitions [Text Block]

Note 2. Acquisitions

On February 17, 2012, WPZ completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC, in exchange for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments, and 7,531,381 WPZ common units valued at $441 million (Laser Acquisition). The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of WPZ's common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entities primarily own the Laser Gathering System, which is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as 10 miles of gathering lines in southern New York.

On April 27, 2012, WPZ completed the acquisition of 100 percent of the ownership interests in Caiman Eastern Midstream, LLC, from Caiman Energy, LLC (Caiman Acquisition) in exchange for $1.72 billion in cash, net of purchase price adjustments, and 11,779,296 WPZ common units valuedat $603 million.The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of WPZ's common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale.Theacquired entityoperates a gathering and processing business in northern West Virginia, southwestern Pennsylvania and eastern Ohio. Acquisition transaction costs of $16 million were incurred related to the Caiman Acquisition and are reported in selling, general and administrative expensesat Williams Partners in the Consolidated Statement of Income.

These acquisitions were accounted for as business combinations which, among other things, require assets acquired and liabilities assumed to be measured at their acquisition-date fair values. The excess of cost over those fair valueswas allocated to goodwill within the Williams Partners segment.

The amounts recognized in the financial statements are preliminary because our valuation work has not been completed. For the Laser Acquisition, we are awaiting further information for valuing intangible assets, contingent liabilities and asset retirement obligations. For the Caiman Acquisition, we are awaiting further information for valuing the working capital components, property, plant and equipment, intangible assets, contingent liabilities and asset retirement obligations. In addition, we are still in the process of identifying all the assets acquired and liabilities assumed.

The following table presents a preliminary allocation of the acquisition-date fair value of the major classes of the net assets, which are presented in the Williams Partners segment:

		Laser		Caiman
Assets held for sale		$	18	$	-
Other current assets			3		13
Property, plant and equipment			158		665
Intangible assets			318		1,313
Current liabilities			(21)		(98)
	Identifiable net assets acquired		476		1,893
Goodwill			290		434
		$	766	$	2,327

Identifiable intangible assets recognized to datein the acquisitions are primarily related to gas gathering, processing and fractionation agreements and relationships with customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired customer contracts and relationships, which are offset with appropriate charges for the use of contributory assets and discounted using a risk-adjusted discount rate. Those intangible assets are being amortizedon a straight-line basis over an initial 30-year period during which the customer contracts and relationships are expected to contribute to our cash flows.We expense costs incurred to renew or extend the terms of our gas gathering, processing and fractionation agreementswith customers.

We will evaluate these intangible assets for both changes in the expected remaining useful lives and impairment when events or changes in circumstances indicate, in our management's judgment, that the estimated useful lives have changed or the carrying value of such assets may not be recoverable. Changes in an estimated remaining useful life would be reflected prospectively through amortization over the revised remaining useful life. When an indicator of impairment has occurred, we compare our management's estimate of undiscounted future cash flows attributable to the intangible assets to the carrying value of the assets to determine whether an impairment has occurred and we apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Goodwill recognized in the acquisitionsrelates primarily to enhancing our strategic platform for expansion in the area. We are currently evaluating the appropriate reporting unitfor the allocation of the goodwill within the Williams Partners segment. The goodwillis not subject to amortization but will be evaluated annually for impairment or more frequently if impairment indicators are present. Our evaluation will include a qualitative assessment of events or circumstances to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount. If so, we will further compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss will be recognized in the amount of the excess.All of the goodwill is expected to be deductible for tax purposes.

Revenues and earnings related to the Laser and Caiman Acquisitionsincluded within the Consolidated Statement of Incomesince the respective acquisition dates are not material. Supplemental pro forma revenue and earnings reflecting these acquisitions as if they had occurred as of January 1, 2011, are not materially different from the information presented in our accompanying Consolidated Statement of Income (since the historical operations of these acquisitions were insignificant relative to our historical operations) and are, therefore, not presented.

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Employee Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2012

Employee Benefit Plans [Abstract]

Net periodic benefit expense

		Pension Benefits
		Three months				Six months
		ended June 30,				ended June 30,
		2012		2011		2012		2011
			(Millions)
Components of net periodic benefit expense:
	Service cost	$	9	$	10	$	19	$	20
	Interest cost		14		15		28		32
	Expected return on plan assets		(16)		(19)		(32)		(38)
	Amortization of net actuarial loss		14		10		27		19
	Net actuarial loss from settlements		2		-		2		-
	Net periodic benefit expense	$	23	$	16	$	44	$	33
		Other Postretirement Benefits
		Three months				Six months
		ended June 30,				ended June 30,
		2012		2011		2012		2011
			(Millions)
Components of net periodic benefit expense:
	Service cost	$	-	$	-	$	1	$	1
	Interest cost		3		3		6		7
	Expected return on plan assets		(2)		(2)		(4)		(5)
	Amortization of prior service cost (credit)		(1)		(2)		(3)		(5)
	Amortization of net actuarial loss		1		1		4		2
	Net periodic benefit expense	$	1	$	-	$	4	$	-

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Provision (Benefit) for Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Mar. 31, 2011	Jun. 30, 2012	Jun. 30, 2011
Current :
Federal	$ 33	$ 59		$ 54	$ 88
State	4	5		8	8
Foreign	3	14		24	(6)
Total	40	78		86	90
Deferred:
Federal	30	25		117	(7)
State	(3)	2		(6)	(1)
Foreign	4	4		7	5
Total	31	31		118	(3)
Total provision (benefit)	71	109		204	87
Provision Benefit for Income Taxes (Textuals) [Abstract]
Tax benefit from settlements and revised assessment					(124)
Decrease in unrecognized tax benefits			$ 62

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Derivative Instruments

6 Months Ended

Jun. 30, 2012

Derivative Instruments [Abstract]

Derivative Instruments Disclosures

Note 12. Derivative Instruments

Energy Commodity Derivatives

Risk management activities

We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage our exposure to the variability in expected future cash flows from forecasted purchases and sales of natural gasand 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 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. In addition, we buy NGLs as feedstock to generate 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.

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 two types:

• Central hub risk: Includes physical and financial derivative exposures to Henry Hub for natural gas 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.

The following table depicts the notional quantities of the net long (short) positions in our commodity derivatives portfolio as of June 30, 2012. Natural gas is presented in millions of British Thermal Units (MMBtu) and NGLsare presented in barrels.

		Unit of	Central Hub
Derivative Notional Volumes		Measure	Risk	Basis Risk
Designated as Hedging Instruments
	Williams Partners	Barrels	(1,770,000)
	Williams Partners	MMBtu	7,810,800	6,504,400
Not Designated as Hedging Instruments
	Williams Partners	Barrels	115,000	255,000
	Midstream Canada & Olefins	Barrels	(220,000)

Gains (losses)

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 June 30,				Six months ended June 30,
		2012		2011		2012		2011		Classification
			(Millions)				(Millions)
Net gain (loss) recognized in other comprehensive
	income (loss) (effective portion)	$	55	$	(4)	$	46	$	(6)	AOCI
Net gain (loss) reclassified from accumulated
	other comprehensive income (loss) into									Revenues or Costs and
	income (effective portion)	$	8	$	(4)	$	6	$	(4)	Operating Expenses

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

We recognized gains of $3million and losses of$1 million in revenues for the six monthsended June 30, 2012 and 2011, respectively, on our energy commodity derivatives not designated as hedging instruments.We also recognized gains of $2 million and losses of less than $1 million in revenues for the three months ended June 30, 2012 and 2011, respectively, on our energy commodity derivatives not designated as hedging instruments. In addition, we recognized gains of less than $1 million in costs and operating expensesfor the six months ended June 30, 2012, on our energy commodity derivatives not designated as hedging instruments.

The cash flow impact of our derivative activities is presented in the Consolidated Statement of Cash Flows as other, including changes in noncurrent 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.

At both June 30, 2012, and December 31, 2011, we did not have any collateral posted, either in the form of cash or letters of credit, to derivative counterparties.

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 ofJune 30, 2012, we have hedged portions of future cash flows associated with anticipated energy commodity purchases and sales through the end of 2012. Based on recorded values atJune 30, 2012, $40 million of pre-tax net gains will be reclassified into earnings within the next six months. These recorded values are based on market prices of the commodities as of June 30, 2012. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized within the next six months 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.