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 September 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)

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

NO CHANGE

(Former name, former address and former fiscal year, if changed since last report.)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  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 October 26, 2012
Common Stock, $1 par value	627,327,174 Shares

The Williams Companies, Inc.

Index

	Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Income – Three and Nine Months Ended September 30, 2012 and 2011		3
Consolidated Statement of Comprehensive Income – Three and Nine Months Ended September  30, 2012 and 2011		4
Consolidated Balance Sheet – September 30, 2012 and December 31, 2011		5
Consolidated Statement of Changes in Equity – Nine Months Ended September 30, 2012		6
Consolidated Statement of Cash Flows – Nine Months Ended September 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		28
Item 3. Quantitative and Qualitative Disclosures About Market Risk		53
Item 4. Controls and Procedures		55
Part II. Other Information		56
Item 1. Legal Proceedings		56
Item 6. Exhibits		57

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,” “assumes,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “guidance,” “outlook,” “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.

1

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

• 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.

2

PART I – FINANCIAL INFORMATION

The Williams Companies, Inc.

Consolidated Statement of Income

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
(Millions, except per-share amounts)	2012			2011			2012			2011
Revenues:
Williams Partners	$	1,527		$	1,673		$	4,795		$	4,923
Midstream Canada & Olefins		231			326			847			989
Other		7			6			20			19
Intercompany eliminations		(13	)		(33	)		(45	)		(104	)
Total revenues		1,752			1,972			5,617			5,827
Segment costs and expenses:
Costs and operating expenses		1,226			1,392			3,927			4,101
Selling, general, and administrative expenses		96			75			294			233
Other (income) expense – net		14			—			31			(3	)
Total segment costs and expenses		1,336			1,467			4,252			4,331
General corporate expenses		43			48			133			140
Operating income (loss):
Williams Partners		343			431			1,113			1,278
Midstream Canada & Olefins		72			73			245			219
Other		1			1			7			(1	)
General corporate expenses		(43	)		(48	)		(133	)		(140	)
Total operating income (loss)		373			457			1,232			1,356
Interest accrued		(140	)		(153	)		(421	)		(464	)
Interest capitalized		11			7			33			17
Investing income – net		33			43			163			127
Other income (expense) – net		—			—			(1	)		4
Income (loss) from continuing operations before income taxes		277			354			1,006			1,040
Provision (benefit) for income taxes		77			33			281			120
Income (loss) from continuing operations		200			321			725			920
Income (loss) from discontinued operations		3			21			138			103
Net income (loss)		203			342			863			1,023
Less: Net income attributable to noncontrolling interests		48			70			153			203
Net income (loss) attributable to The Williams Companies, Inc.	$	155		$	272		$	710		$	820
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations	$	152		$	253		$	572		$	724
Income (loss) from discontinued operations		3			19			138			96
Net income (loss)	$	155		$	272		$	710		$	820
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	.25		$	.43		$	.94		$	1.23
Income (loss) from discontinued operations		—			.03			.22			.16
Net income (loss)	$	.25		$	.46		$	1.16		$	1.39
Weighted-average shares (thousands)		626,809			588,950			613,888			588,082
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	.25		$	.43		$	.93		$	1.21
Income (loss) from discontinued operations		—			.03			.22			.16
Net income (loss)	$	.25		$	.46		$	1.15		$	1.37
Weighted-average shares (thousands)		632,019			597,550			619,765			597,250
Cash dividends declared per common share	$	.3125		$	.200		$	.87125		$	.525

See accompanying notes.

3

The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income

(Unaudited)

	Three months ended  September 30,						Nine months ended September 30,
(Millions)	2012			2011			2012			2011
Net income (loss)	$	203		$	342		$	863		$	1,023
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $3 and ($9) in 2012 and ($79) and ($100) in 2011		(9	)		124			25			155
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $3 and $5 in 2012 and $30 and $83 in 2011		(11	)		(41	)		(15	)		(126	)
Foreign currency translation adjustments		30			(66	)		32			(39	)
Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit expense, net of taxes of $1 and $1 in 2011		—			—			(1	)		(1	)
Net actuarial gain (loss) arising during the year, net of taxes of $1 and $2 in 2012 and $2 and $2 in 2011		(1	)		(4	)		(4	)		(4	)
Amortization of actuarial (gain) loss included in net periodic benefit expense, net of taxes of ($6) and ($17) in 2012 and ($5) and ($12) in 2011		10			9			29			21
Equity securities:
Unrealized gain (loss) on equity securities, net of taxes of ($1) in 2011		—			(1	)		—			2
Reclassifications into earnings of (gain) loss on sale of equity securities, net of taxes of $2 in 2012		—			—			(3	)		—
Other comprehensive income (loss)		19			21			63			8
Comprehensive income (loss)		222			363			926			1,031
Less: Comprehensive income (loss) attributable to noncontrolling interest		40			70			157			203
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	182		$	293		$	769		$	828

See accompanying notes.

4

The Williams Companies, Inc.

Consolidated Balance Sheet

(Unaudited)

	September 30,			December 31,
(Dollars in millions, except per-share amounts)	2012			2011
ASSETS
Current assets:
Cash and cash equivalents	$	996		$	889
Accounts and notes receivable		624			637
Inventories		161			169
Regulatory assets		38			40
Other current assets and deferred charges		142			159
Total current assets		1,961			1,894
Investments		1,626			1,391
Property, plant, and equipment, at cost		21,600			19,082
Accumulated depreciation and amortization		(6,916	)		(6,502	)
Property, plant, and equipment - net		14,684			12,580
Goodwill		650			—
Other intangibles		1,726			44
Regulatory assets, deferred charges, and other		616			593
Total assets	$	21,263		$	16,502
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	768		$	691
Accrued liabilities		609			631
Long-term debt due within one year		2			353
Total current liabilities		1,379			1,675
Long-term debt		9,512			8,369
Deferred income taxes		2,648			2,157
Regulatory liabilities, deferred income, and other		1,733			1,715
Contingent liabilities (Note 13)
Equity:
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 662 million shares issued at September 30, 2012 and 626 million shares issued at December 31, 2011)		662			626
Capital in excess of par value		9,449			7,920
Retained deficit		(5,648	)		(5,820	)
Accumulated other comprehensive income (loss)		(330	)		(389	)
Treasury stock, at cost (35 million shares of common stock)		(1,041	)		(1,041	)
Total stockholders’ equity		3,092			1,296
Noncontrolling interests in consolidated subsidiaries		2,899			1,290
Total equity		5,991			2,586
Total liabilities and equity	$	21,263		$	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)		—		—		710			—			—			710			153			863
Other comprehensive income (loss)		—		—		—			59			—			59			4			63
Cash dividends – common stock		—		—		(538	)		—			—			(538	)		—			(538	)
Dividends and distributions to noncontrolling interests		—		—		—			—			—			—			(284	)		(284	)
Issuance of common stock from debentures conversion		1		5		—			—			—			6			—			6
Stock-based compensation and related common stock issuances, net of tax		5		79		—			—			—			84			—			84
Sales of limited partner units of Williams Partners L.P.		—		—		—			—			—			—			1,559			1,559
Issuances 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		—		586		—			—			—			586			(935	)		(349	)
Sale of common stock		30		857		—			—			—			887			—			887
Reconsolidation of noncontrolling interest in Wilpro entities (see Note 3)		—		—		—			—			—			—			65			65
Other		—		2		—			—			—			2			3			5
Balance – September 30, 2012	$	662	$	9,449	$	(5,648	)	$	(330	)	$	(1,041	)	$	3,092		$	2,899		$	5,991

See accompanying notes.

6

The Williams Companies, Inc.

Consolidated Statement of Cash Flows

(Unaudited)

	Nine months ended September 30,
(Millions)	2012			2011
OPERATING ACTIVITIES:
Net income (loss)	$	863		$	1,023
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation, depletion, and amortization		545			1,202
Provision (benefit) for deferred income taxes		117			77
Provision for loss on investments, property and other assets		—			130
Net (gain) loss on dispositions of assets		(56	)		(7	)
Gain on reconsolidation of Wilpro entities (Note 3)		(144	)		—
Amortization of stock-based awards		27			36
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable		82			(180	)
Inventories		19			15
Other current assets and deferred charges		28			(1	)
Accounts payable		(165	)		165
Accrued liabilities		14			(67	)
Other, including changes in noncurrent assets and liabilities		(41	)		(41	)
Net cash provided (used) by operating activities		1,289			2,352
FINANCING ACTIVITIES:
Proceeds from long-term debt		2,109			1,100
Payments of long-term debt		(1,313	)		(824	)
Proceeds from issuance of common stock		935			34
Proceeds from sale of limited partner units of consolidated partnership		1,559			—
Dividends paid		(538	)		(309	)
Dividends and distributions paid to noncontrolling interests		(246	)		(159	)
Distributions paid to noncontrolling interests on sale of Wilpro assets (Note 3)		(38	)		—
Other – net		30			(5	)
Net cash provided (used) by financing activities		2,498			(163	)
INVESTING ACTIVITIES:
Capital expenditures*		(1,652	)		(1,833	)
Contributions to equity method investments		(282	)		(150	)
Purchases of businesses		(2,049	)		(41	)
Proceeds from dispositions of investments		79			15
Cash of Wilpro entities upon reconsolidation (Note 3)		121			—
Other – net		103			21
Net cash provided (used) by investing activities		(3,680	)		(1,988	)
Increase (decrease) in cash and cash equivalents		107			201
Cash and cash equivalents at beginning of period		889			795
Cash and cash equivalents at end of period	$	996		$	996
*       Increases to property, plant, and equipment	$	(1,784	)	$	(1,914	)
Changes in related accounts payable and accrued liabilities		132			81
Capital expenditures	$	(1,652	)	$	(1,833	)

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. In August 2012, WPZ completed a public equity issuance of 9,775,000 common units representing limited partner interests. Following these transactions, as of September 30, 2012, we own approximately 66 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 $1.668 billion, capital in excess of par value by $586 million and deferred income taxes by $349 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 September 30, 2012, the Consolidated Balance Sheet includes $438 million of Gulfstar construction work in process representing costs incurred to date, included in property, plant, and equipment, at cost and $109 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 $550 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 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 subject to certain closing 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 recorded as goodwill and allocated to our midstream businesses (the reporting unit) within the Williams Partners segment. Goodwill recognized in the acquisitions relates primarily to enhancing our strategic platform for expansion in the Marcellus and Utica shale plays in the Appalachian basin area. Substantially all of the goodwill is expected to be deductible for tax purposes.

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

The following table presents the 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			663
Intangible assets:
Customer contracts		316			1,141
Customer relationships		—			250
Other intangible assets		2			2
Current liabilities		(21	)		(98	)
Noncurrent liabilities		—			(4	)
Identifiable net assets acquired		476			1,967
Goodwill		290			360
	$	766		$	2,327

During the third quarter of 2012, we recognized measurement period adjustments related to the Caiman Acquisition that primarily increased the fair value of the identifiable intangible assets by $80 million at the acquisition date, offset by a decrease to goodwill based on more refined estimates of future cash flows from the identifiable intangible assets. An increase in amortization expense since the acquisition date was also recorded related to this adjustment.

Identifiable intangible assets recognized in the acquisitions are primarily related to gas gathering, processing and fractionation contracts 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 contracts with customers. Approximately 70 and 36 percent of the expected future revenues from the customer contracts associated with the Laser and Caiman Acquisitions, respectively, are impacted by our ability and intent to renew or renegotiate existing customer contracts. Based on the estimated future revenues during the current contract periods, the weighted-average periods prior to the next renewal or extension of the existing customer contracts associated with the Laser and Caiman Acquisitions are approximately 9 and 18 years, respectively.

10

Notes (Continued)

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.

The goodwill is not subject to amortization but will be evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present. Our evaluation will include an 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.

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 September 30,						Nine months ended September 30,
	2012			2011			2012			2011
	(Millions)
Revenues	$	—		$	1,025		$	—		$	3,002
Income (loss) from discontinued operations before gain on reconsolidation, impairment and income taxes	$	(2	)	$	48		$	(12	)	$	191
Gain on reconsolidation		—			—			144			—
Impairment		—			(5	)		—			(16	)
(Provision) benefit for income taxes		5			(22	)		6			(72	)
Income (loss) from discontinued operations	$	3		$	21		$	138		$	103
Income (loss) from discontinued operations:
Attributable to noncontrolling interests	$	—		$	2		$	—		$	7
Attributable to The Williams Companies, Inc.	$	3		$	19		$	138		$	96

11

Notes (Continued)

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 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 have resulted 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 nine months ended September 30, 2011, for our former exploration and production business’ energy commodity derivatives.

	Three months ended September 30, 2011		Nine months ended September 30, 2011		Classification
	(Millions)
Designated as cash flow hedges
Net gain (loss) recognized in other comprehensive income (loss) (effective portion)	$	212	$	270	Accumulated other comprehensive income (loss) (AOCI)
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$	77	$	219	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	$	11	$	17	Income (loss) from discontinued operations

12

Notes (Continued)

Note 4. Asset Sales and Other Accruals

We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December 28, 2010. We recorded charges of $1 million and $6 million during the three months ended September 30, 2012 and 2011, respectively, and $2 million and $13 million during the nine months ended September 30, 2012 and 2011, respectively, to costs and operating expenses at Williams Partners primarily related to assessment and monitoring costs incurred to ensure the safety of the surrounding area.

Other (income) expense – net within segment costs and expenses at Williams Partners in the nine months ended September 30, 2012, includes $17 million of project feasibility costs associated with natural gas pipeline expansion projects. The nine months ended September 30, 2011, includes a $10 million reversal of project feasibility costs from expense to capital. 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.

General corporate expenses for the three and nine months ended September 30, 2012, includes $6 million and $14 million, respectively, of expense related to our engagement of a consulting firm to assist in better aligning resources to support our business strategy following the spin-off of WPX.

Investing income – net at Other includes income of $63 million and $11 million in the nine months ended September 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.

Note 5. Provision (Benefit) for Income Taxes

The provision (benefit) for income taxes includes:

	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
	(Millions)						(Millions)
Current:
Federal	$	58		$	31		$	112		$	119
State		10			7			18			15
Foreign		6			9			30			3
		74			47			160			137
Deferred:
Federal		6			(16	)		123			(23	)
State		(3	)		(2	)		(9	)		(3	)
Foreign		—			4			7			9
		3			(14	)		121			(17	)
Total provision (benefit)	$	77		$	33		$	281		$	120

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

13

Notes (Continued)

The effective income tax rate for the total provision for the nine months ended September 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 September 30, 2011, is less than the federal statutory rate primarily due to the reversal of previously provided deferred taxes on undistributed earnings of certain foreign operations that are considered to be permanently reinvested, the impact of nontaxable noncontrolling interests and federal settlements.

The effective income tax rate for the total provision for the nine months ended September 30, 2011, is less than the federal statutory rate primarily due to federal settlements, an international revised assessment, the impact of nontaxable noncontrolling interests, the reversal of previously provided deferred taxes on undistributed earnings of certain foreign operations that are considered to be permanently reinvested and taxes on foreign operations.

During the third quarter of 2012, we reached a tentative agreement subject to government approval with the Internal Revenue Service (IRS) on tax matters related to the IRS’s examination of our 2009 and 2010 consolidated corporate income tax returns. These matters resulted in a tax provision of approximately $2 million recorded during the third quarter of 2012. With respect to the examined years, we anticipate making approximately $12 million of cash payments to the IRS in the fourth quarter of 2012.

During the first quarter of 2011, we finalized settlements for 1997 through 2008 on certain contested matters with the IRS and also received a revised assessment on an international matter. These settlements and revised assessment resulted in a 2011 year-to-date tax benefit of approximately $135 million. 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. In July and August 2011, we made cash payments to the IRS of $82 million and $77 million, respectively, related to these settlements.

In the fourth quarter of 2010, we provided $66 million of deferred taxes on the undistributed earnings of certain foreign operations that we no longer could assert were permanently reinvested due to alternatives being considered related to an existing structure impacted by the potential timing of our plan approved by our Board of Directors to pursue the separation of our exploration and production business through an IPO and subsequent tax-free spin-off. During the third quarter of 2011, associated with a ruling received from the IRS related to this separation plan, and following a certain internal reorganization, we recognized a deferred tax benefit of $66 million as we considered the undistributed earnings of these certain foreign operations to be permanently reinvested.

On December 23, 2011, the IRS 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				Nine months ended
	September 30,				September 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	$	152	$	253	$	572	$	724
Basic weighted-average shares		626,809		588,950		613,888		588,082
Effect of dilutive securities:
Nonvested restricted stock units		2,490		3,767		2,721		3,925
Stock options		2,535		3,029		2,695		3,342
Convertible debentures		185		1,804		461		1,901
Diluted weighted-average shares		632,019		597,550		619,765		597,250
Earnings (loss) per common share from continuing operations:
Basic	$	.25	$	.43	$	.94	$	1.23
Diluted	$	.25	$	.43	$	.93	$	1.21

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 nine months ended September 30, 2012, is immaterial.

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

	September 30,
	2012		2011
Options excluded (millions)		—		3.0
Weighted-average exercise price of options excluded		N/A		$31.41
Exercise price ranges of options excluded		N/A		$28.30 - $37.88
Third quarter weighted-average market price		$32.05		$27.72

Note 7. Employee Benefit Plans

Net periodic benefit expense is as follows:

	Pension Benefits
	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
	(Millions)
Components of net periodic benefit expense:
Service cost	$	10		$	11		$	29		$	31
Interest cost		14			16			42			48
Expected return on plan assets		(16	)		(20	)		(48	)		(58	)
Amortization of prior service cost (credit)		—			1			—			1
Amortization of net actuarial loss		13			9			40			28
Net actuarial loss from settlements		2			4			4			4
Net periodic benefit expense	$	23		$	21		$	67		$	54

15

Notes (Continued)

	Other Postretirement Benefits
	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
	(Millions)
Components of net periodic benefit expense:
Service cost	$	1		$	1		$	2		$	2
Interest cost		4			4			10			11
Expected return on plan assets		(3	)		(3	)		(7	)		(8	)
Amortization of prior service cost (credit)		(2	)		(3	)		(5	)		(8	)
Amortization of net actuarial loss		2			1			6			3
Amortization of regulatory asset		—			1			—			1
Net periodic benefit expense	$	2		$	1		$	6		$	1

During the nine months ended September 30, 2012, we contributed $77 million to our pension plans and $10 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $2 million to our pension plans and approximately $4 million to our other postretirement benefit plans in the remainder of 2012.

Note 8. Inventories

	September 30, 2012		December 31, 2011
	(Millions)
Natural gas liquids, olefins, and natural gas in underground storage	$	88		$	98
Materials, supplies, and other		73			71
	$	161		$	169

Note 9. Debt and Banking Arrangements

Credit Facilities

In September 2012, WPZ amended its existing $2 billion senior unsecured revolving credit facility to increase the aggregate commitments by $400 million. This facility was also amended to provide that WPZ may request an additional $400 million increase in commitments to be available under certain conditions in the future.

Letter of credit capacity under our $900 million and WPZ’s now $2.4 billion credit facilities is $700 million and $1.3 billion, respectively. At September 30, 2012, no letters of credit have been issued and no loans are outstanding on either facility. We have issued letters of credit totaling $24 million as of September 30, 2012, under certain bilateral bank agreements.

Issuances and Retirements

In August 2012, WPZ completed a public offering of $750 million of 3.35 percent senior unsecured notes due 2022. WPZ used the net proceeds to repay outstanding borrowings on its senior unsecured revolving credit facility and for general partnership purposes.

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 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 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.

16

Notes (Continued)

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
							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 September 30, 2012:
Measured on a recurring basis:
ARO Trust investments	$	21		$	21		$	21		$	—		$	—
Energy derivatives assets not designated as hedging instruments		2			2			1			1			—
Energy derivatives assets designated as hedging instruments		15			15			9			6			—
Energy derivatives liabilities not designated as hedging instruments		(1	)		(1	)		(1	)		—			—
Additional disclosures:
Notes receivable and other		109			114			1			9			104
Long-term debt, including current portion (a)		(9,511	)		(11,258	)		—			(11,258	)		—
Guarantee		(33	)		(31	)		—			(31	)		—
Customer margin deposits payable		(6	)		(6	)		(6	)		—			—
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

17

Notes (Continued)

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, is classified as available-for-sale, and is 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 derivative contracts expiring in the next six 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 nine months ended September 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 scheduled payments. The carrying value and disclosed fair value of this note is $62 million and $67 million, respectively, at September 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 portion is reported in accounts and notes receivable, and the noncurrent portion is reported in regulatory assets, deferred charges, and other 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 is 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 September 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 $239 million at September 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: Financial derivative exposures to Henry Hub for natural gas and Mont Belvieu for NGLs;

• Basis risk: 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 September 30, 2012. Natural gas is presented in millions of British Thermal Units (MMBtu) and NGLs are presented in barrels.

	Unit of	Central Hub
Derivative Notional Volumes	Measure	Risk			Basis Risk
Designated as Hedging Instruments
Williams Partners	Barrels		(885,000	)
Williams Partners	MMBtu		3,905,400			3,252,200
Not Designated as Hedging Instruments
Williams Partners	Barrels		(20,000	)		165,000
Midstream Canada & Olefins	Barrels		(155,000	)

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 September 30,						Nine months ended September 30,
	2012			2011			2012		2011			Classification
	(Millions)						(Millions)
Net gain (loss) recognized in other comprehensive income (loss) (effective portion)	$	(12	)	$	(8	)	$	34	$	(14	)	AOCI
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$	13		$	(6	)	$	19	$	(10	)	Revenues or Costs and Operating Expenses

20

Notes (Continued)

We recognized gains of less than $1 million in income as a result of hedge ineffectiveness for the nine months ended September 30, 2012. There were no gains or losses recognized in income 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 $2 million and losses of $2 million in revenues for the nine months ended September 30, 2012 and 2011, respectively, 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 September 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 September 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 September 30, 2012, $14 million of pre-tax net gains will be reclassified into earnings within the next three months. These recorded values are based on forward market prices of the commodities as of September 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 three 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 and certain California utilities have agreed in principle to resolve WPX’s collection of accrued interest from counterparties as well as WPX’s payment of accrued interest on refund amounts. As currently contemplated by the parties, the settlement, which is subject to FERC and California regulatory approval, would resolve most 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 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

22

Notes (Continued)

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 remaining 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 original breach of contract claims involving Gulsby and attorney fee claims (the remaining claims) 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 September 30, 2012, we have accrued liabilities totaling $44 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.

23

Notes (Continued)

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 biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At September 30, 2012, we have accrued liabilities of $10 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 September 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 September 30, 2012, we have accrued environmental liabilities of $26 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 September 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, natural gas, 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 $83 million and $235 million for the three months and nine months ended September 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 $205 million and $634 million for the three months and nine months ended September 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 September 30, 2012
Segment revenues:
External	$	1,518	$	229		$	5		$	—		$	1,752
Internal		9		2			2			(13	)		—
Total revenues	$	1,527	$	231		$	7		$	(13	)	$	1,752
Segment profit (loss)	$	373	$	72		$	1		$	—		$	446
Less:
Equity earnings (losses)		30		—			—			—			30
Segment operating income (loss)	$	343	$	72		$	1		$	—			416
General corporate expenses													(43	)
Total operating income (loss)												$	373
Three months ended September 30, 2011
Segment revenues:
External	$	1,643	$	325		$	4		$	—		$	1,972
Internal		30		1			2			(33	)		—
Total revenues	$	1,673	$	326		$	6		$	(33	)	$	1,972
Segment profit (loss)	$	471	$	73		$	1		$	—		$	545
Less:
Equity earnings (losses)		40		—			—			—			40
Segment operating income (loss)	$	431	$	73		$	1		$	—			505
General corporate expenses													(48	)
Total operating income (loss)												$	457
Nine months ended September 30, 2012
Segment revenues:
External	$	4,764	$	841		$	12		$	—		$	5,617
Internal		31		6			8			(45	)		—
Total revenues	$	4,795	$	847		$	20		$	(45	)	$	5,617
Segment profit (loss)	$	1,200	$	243		$	61		$	—		$	1,504
Less:
Equity earnings (losses)		87		—			1			—			88
Income (loss) from investments		—		(2	)		53			—			51
Segment operating income (loss)	$	1,113	$	245		$	7		$	—			1,365
General corporate expenses													(133	)
Total operating income (loss)												$	1,232
Nine months ended September 30, 2011
Segment revenues:
External	$	4,831	$	985		$	11		$	—		$	5,827
Internal		92		4			8			(104	)		—
Total revenues	$	4,923	$	989		$	19		$	(104	)	$	5,827
Segment profit (loss)	$	1,379	$	219		$	23		$	—		$	1,621
Less:
Equity earnings (losses)		101		—			13			—			114
Income (loss) from investments		—		—			11			—			11
Segment operating income (loss)	$	1,278	$	219		$	(1	)	$	—			1,496
General corporate expenses													(140	)
Total operating income (loss)												$	1,356
September 30, 2012
Total assets (a)	$	18,873	$	1,404		$	1,308		$	(322	)	$	21,263
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 Laser Acquisition in the first quarter of 2012 and the Caiman Acquisition in the second quarter of 2012. (See Note 2.)

26

Notes (Continued)

Note 15. Subsequent Events

In October 2012, WPZ agreed to purchase our 83.3 percent undivided interest and operatorship of the olefins-production facility in Geismar, Louisiana, along with our refinery grade propylene splitter and pipelines in the Gulf region for total consideration valued at approximately $2.364 billion. WPZ expects to fund substantially all of the transaction with the issuance of limited partner units to us. The transaction is expected to close in November 2012.

27

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 66 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 NGL-rich portion of the Marcellus Shale. (See Results of Operations – Segments, Williams Partners.)

Dividends

In March, June, and September 2012, we paid regular quarterly dividends on a per share basis of $0.25875, $0.30, and $0.3125, respectively. 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 Nine Months Ended September 30, 2012

Income (loss) from continuing operations attributable to The Williams Companies, Inc., for the nine months ended September 30, 2012, changed unfavorably by $152 million compared to the nine months ended September 30, 2011. This change reflects:

• A $165 million unfavorable change in operating income at Williams Partners primarily due to lower NGL production and marketing margins, higher operating costs and selling, general, and administrative expenses (SG&A), partially offset by an increase in fee revenues. (See Results of Operations – Segments, Williams Partners.);

• The absence of both a $135 million net tax benefit recorded in 2011 associated with federal settlements and an international revised assessment and a $66 million tax benefit recognized in 2011 associated with undistributed earnings of certain foreign operations that we considered to be permanently reinvested;

28

Management’s Discussion and Analysis (Continued)

• An improvement in operating income at Midstream Canada & Olefins as well as favorable changes in net income attributable to noncontrolling interests, interest accrued, and investing income-net.

See additional discussion in Results of Operations.

Our net cash provided by operating activities for the nine months ended September 30, 2012, decreased $1.063 billion compared to the nine months ended September 30, 2011, largely due to the absence of operating cash flows from our former exploration and production business and lower operating results.

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. We received the first and second quarterly installment payments in June and September 2012, respectively. 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.

29

Management’s Discussion and Analysis (Continued)

• 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 completed an agreement with Caiman Energy, LLC and others 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.

• 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. 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 August 2012, WPZ completed an equity issuance of 8,500,000 common units representing limited partner interests at a price of $51.43 per unit. Subsequently, WPZ sold an additional 1,275,000 common units for $51.43 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds of these transactions were primarily used to repay outstanding borrowings on WPZ’s senior unsecured revolving credit facility (WPZ’s revolver).

• In August 2012, WPZ completed a public offering of $750 million of 3.35 percent senior unsecured notes due 2022. The net proceeds were used to repay outstanding borrowings on WPZ’s revolver and for general partnership purposes.

• In October 2012, WPZ agreed to acquire our 83.3 percent undivided interest and operatorship of an olefins-production facility located in Geismar, Louisiana, along with our refinery grade propylene splitter and pipelines in the Gulf region. These businesses are currently reported within our Midstream Canada & Olefins segment. WPZ expects to fund substantially all of the transaction with the issuance of limited partner units to us. The transaction is expected to close in November 2012.

• In October 2012, we agreed to acquire twelve idle pipelines in the Gulf Coast region. The acquired pipelines will be combined with an organic build-out of several projects to expand our petrochemical services in that region. The projects are expected to be placed into service beginning in late 2014. Total project costs through 2014, including the acquisition of the pipelines, is expected to total approximately $480 million.

Company Outlook

During the second quarter of 2012, NGL margins declined sharply largely attributable to a record-warm winter, a slowing global economy, and growing NGL supplies. The downward trend of per-unit NGL margins has leveled-off during third quarter 2012 and we anticipate a modest level of improvement through 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 may 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 and significant capital investment. Our planned capital investments for the year total approximately $6.513 billion, including WPZ equity issued in the previously discussed Laser and Caiman Acquisitions. We expect to fund these activities primarily through cash on hand, cash flow from operations, and debt and/or equity issuances. 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 be able to grow 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 our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

30

Management’s Discussion and Analysis (Continued)

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.

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 Estimates

WPZ completed the Laser Acquisition in February 2012 and the Caiman Acquisition in April 2012. Based on the final Laser and preliminary Caiman fair value measurements, our September 30, 2012, Consolidated Balance Sheet includes $650 million of goodwill related to these acquisitions, which we allocated to our midstream business (the reporting unit) within the Williams Partners segment. (See Note 2 of Notes to Consolidated Financial Statements.) We will evaluate the goodwill for impairment annually as of October 1 or more frequently if impairment indicators are present. These indicators may include materially unfavorable changes in market fundamentals such as sustained reductions in producer drilling activity, changes in our business strategy in this area, our ability to fund expected levels of investment and significantly lower than expected operating results. Our evaluation will include an 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.

As a result of these acquisitions, we have also recorded a total of approximately $1.7 billion in intangible assets as of September 30, 2012. The identifiable intangible assets recognized in the acquisitions are primarily related to gas gathering, processing and fractionation contracts and relationships with customers. These 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 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.

31

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

	Three months ended September 30,											Nine months ended September 30,
	2012			2011			$ Change*		% Change*			2012			2011			$ Change*		% Change*
	(Millions)											(Millions)
Revenues	$	1,752		$	1,972			-220		-11	%	$	5,617		$	5,827			-210		-4	%
Costs and expenses:
Costs and operating expenses		1,226			1,392			+166		+12	%		3,927			4,101			+174		+4	%
Selling, general, and administrative expenses		96			75			-21		-28	%		294			233			-61		-26	%
Other (income) expense – net		14			—			-14		NM			31			(3	)		-34		NM
General corporate expenses		43			48			+5		+10	%		133			140			+7		+5	%
Total costs and expenses		1,379			1,515								4,385			4,471
Operating income (loss)		373			457								1,232			1,356
Interest accrued – net		(129	)		(146	)		+17		+12	%		(388	)		(447	)		+59		+13	%
Investing income – net		33			43			-10		-23	%		163			127			+36		+28	%
Other income (expense) – net		—			—			—		—			(1	)		4			-5		NM
Income (loss) from continuing operations before income taxes		277			354								1,006			1,040
Provision (benefit) for income taxes		77			33			-44		-133	%		281			120			-161		-134	%
Income (loss) from continuing operations		200			321								725			920
Income (loss) from discontinued operations		3			21			-18		-86	%		138			103			+35		+34	%
Net income (loss)		203			342								863			1,023
Less: Net income attributable to noncontrolling interests		48			70			+22		+31	%		153			203			+50		+25	%
Net income (loss) attributable to The Williams Companies, Inc.	$	155		$	272							$	710		$	820

* + = 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 September 30, 2012 vs. three months ended September 30, 2011

The decrease in revenues is primarily due to lower NGL production and marketing revenues at Williams Partners reflecting an overall decrease in average NGL per-unit sales prices. The lower NGL marketing revenues are partially offset by higher NGL volumes and new volumes from natural gas marketing activities. In addition, olefins and NGL production 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.

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

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Management’s Discussion and Analysis (Continued)

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

The unfavorable change in operating income (loss) generally reflects decreased NGL production margins primarily driven by energy commodity price changes including lower NGL prices, partially offset by lower natural gas prices, and higher operating costs and SG&A, partially offset by increased fee revenues as previously discussed.

Interest accrued – net changed favorably primarily due to corporate debt retirements in December 2011.

Provision (benefit) for income taxes changed unfavorably primarily due to the absence of $66 million deferred tax benefit recognized in 2011 related to the undistributed earnings of certain foreign operations that we considered to be permanently reinvested. 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 of 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 64 percent at September 30, 2012, compared to 73 percent at September 30, 2011.

Nine months ended September 30, 2012 vs. nine months ended September 30, 2011

The decrease in revenues is primarily due to Williams Partners’ lower NGL production revenues reflecting an overall decrease in average NGL per-unit sales prices as well as Midstream Canada & Olefins’ decreases in olefins and NGL production and marketing revenues primarily due to lower average per-unit sales prices. Partially offsetting these decreases are higher fee revenues at Williams Partners.

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

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 $15 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.

The decrease in general corporate expenses is largely related to the spin-off of our former exploration and production business, which was completed on December 31, 2011. Partially offsetting this decrease is $14 million of expense incurred in 2012 for our engagement of a consulting firm to assist in better aligning resources to support our business strategy following the spin-off of our former exploration and production business.

The unfavorable change in operating income (loss) generally reflects lower NGL production margins primarily due to energy commodity price changes including lower NGL prices, partially offset by lower natural gas prices, a decrease in margins related to the marketing of NGLs, and higher operating costs and SG&A, partially offset by increased fee revenues and higher ethylene margins.

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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 $26 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 the absence of approximately $135 million tax benefit from federal settlements and an international revised assessment in 2011 as well as the absence of $66 million deferred tax benefit recognized in 2011 related to the undistributed earnings of certain foreign operations that we considered to be permanently reinvested. 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 of 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 64 percent at September 30, 2012, compared to 73 percent at September 30, 2011.

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 September 30, 2012, we own approximately 66 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.

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Management’s Discussion and Analysis (Continued)

Gulf Olefins production facilities acquisition

In October 2012, WPZ agreed to purchase our 83.3 percent undivided interest and operatorship of the olefins-production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf region. The acquisition is expected to result in a favorable shift in Williams Partners’ commodity price exposure from ethane to ethylene. These businesses are currently reported within the Midstream Canada & Olefins segment. Located south of Baton Rouge, Louisiana, the Geismar facility is a light-end NGL cracker with current volumes of 39,000 barrels per day (bpd) of ethane and 3,000 bpd of propane and annual production of 1.35 billion pounds of ethylene. With the benefit of an expansion under way and scheduled for completion by late 2013, the facility’s annual ethylene production capacity will grow by 600 million pounds to 1.95 billion pounds. Since the owner of the remaining ownership interest in the facility is not participating in the expansion, WPZ’s overall undivided interest following the expansion will be approximately 88 percent. Along with ethane, propane and ethylene, the Geismar facility also produces propylene, butadiene, and debutanized aromatic concentrate (DAC). This transaction is expected to close in November 2012.

Overview of Nine Months Ended September 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 nearly complete.

The acquisition provides 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 that we 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

In July 2012, 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.

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.

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Management’s Discussion and Analysis (Continued)

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 were completed in the third quarter of 2012 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.

Volume impacts in the third quarter

Our NGL equity sales volumes for the third quarter of 2012 were modestly impacted by maintenance on the Overland Pass Pipeline for approximately 5 days. As a result of the NGL pipeline maintenance, NGL takeaway capacity from our western plants on the Overland Pass Pipeline was reduced, which forced our western plants to reduce NGL recoveries.

In the Gulf Coast, our Mobile Bay plant was shut down for 10 days due to Hurricane Isaac. The plant and offshore platforms were evacuated during the storm. Afterwards, the plant remained shut down due to flooding issues on a third-party pipeline limiting the NGL takeaway capacity. In addition, production into Devils Tower was shut-in for various time periods due to third-party hurricane related issues. These events related to Hurricane Isaac did not have a material impact to our overall NGL production or NGL equity sales.

Volatile commodity prices

Driven primarily by a sharp decline in NGL prices during the second quarter of 2012, followed by increasing natural gas prices in the third quarter of 2012, average per-unit NGL margins have declined during the first nine months of 2012 and were approximately 17 percent lower in the first nine months 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. Despite an increase in natural gas prices during the third quarter of 2012, we have benefited from lower natural gas prices in the first nine months of 2012 than in the same period of 2011, driven by abundant natural gas supplies.

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.

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Management’s Discussion and Analysis (Continued)

Outlook for the Remainder of 2012

Commodity price changes

• We expect our average per-unit NGL margins to improve from third quarter 2012 levels such that our full year 2012 margins are expected to be comparable to our rolling five-year average per-unit NGL margins, but lower than 2011. 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 12 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 ensure a margin on the hedged volumes of $61 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.

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Management’s Discussion and Analysis (Continued)

• In Williams Partners onshore businesses, we anticipate significant growth in our natural gas gathering volumes as our infrastructure grows to support drilling activities 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 certain of our onshore areas and unfavorably impact the supply of natural gas available to gather and process in 2013 and the long term.

• In Williams Partners’ businesses in the Gulf Coast, 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. 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 $5.9 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 $205 million. We placed the first phase of the project into service in September 2012 which increased capacity by 95 Mdth/d. We plan to place the second phase of the project into service in June 2013 which will increase capacity by an additional 130 Mdth/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 the 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.

38

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. We may consider a partner for this project.

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 $92 million, which is expected to be spent through the end of 2013. As of September 30, 2012, we have incurred approximately $62 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.)

39

Management’s Discussion and Analysis (Continued)

Filing of rate cases

On August 31, 2012, Transco filed a general rate case with the FERC for an overall increase in rates. In September 2012, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2013, subject to refund and the outcome of a hearing. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2012 and will not be subject to refund. The impact of these specific new rates that became effective October 1, 2012 is expected to reduce revenues by approximately $4 million for the period from October 1, 2012 until the remaining rates that are currently suspended become effective on March 1, 2013.

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 September 30,				Nine months ended September 30,
	2012		2011		2012		2011
	(Millions)
Segment revenues	$	1,527	$	1,673	$	4,795	$	4,923
Segment profit	$	373	$	471	$	1,200	$	1,379

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

The decrease in segment revenues includes:

• A $99 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $121 million associated with an overall 36 percent decrease in average NGL per-unit sales prices. Average ethane and non-ethane per-unit prices decreased by 60 percent and 23 percent, respectively.

• A $51 million decrease in marketing revenues primarily due to lower NGL prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities. These changes are offset by similar changes in marketing purchases and resulted in insignificant margins in the third quarter of 2012.

• A $21 million decrease in system management gas sales from our gas pipeline businesses (offset in segment costs and expenses).

• A $27 million increase in fee revenues primarily due to higher volumes in the Marcellus Shale, including new volumes on our recently acquired natural gas gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses.

Segment costs and expenses decreased $58 million, including:

• A $57 million decrease in marketing purchases primarily due to lower average NGL prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities.

• A $32 million decrease in costs associated with our equity NGLs primarily due to a 35 percent decrease in average natural gas prices.

40

Management’s Discussion and Analysis (Continued)

• A $21 million decrease in system management gas costs from our gas pipeline businesses (offset in segment revenues).

• A $37 million increase in operating costs primarily due to higher depreciation and amortization of assets and intangibles acquired in 2012 and increased depreciation on certain assets in the Gulf Coast region resulting from a change in the estimated useful lives, partially offset by lower costs related to the Eminence storage facility leak.

• A $20 million increase in general and administrative expenses including increases in employee-related expenses and information technology costs driven by general growth within our business operations, along with acquisition and transition-related costs.

The decrease in segment profit includes:

• A $67 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices.

• A $37 million increase in operating costs as previously discussed.

• A $20 million increase in general and administrative expenses as previously discussed.

• A $10 million decrease in equity earnings primarily due to $5 million lower Discovery equity earnings, primarily due to lower NGL margins and volumes, and $5 million lower Aux Sable equity earnings primarily due to lower NGL margins.

• A $27 million increase in fee revenues as previously discussed.

Nine months ended September 30, 2012 vs. nine months ended September 30, 2011

The decrease in segment revenues includes:

• A $210 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $225 million associated with an overall 24 percent decrease in average NGL per-unit sales prices. Average ethane and non-ethane per-unit prices decreased by 41 percent and 13 percent, respectively.

• A $48 million decrease in system management gas sales from our gas pipeline businesses (offset in segment costs and expenses).

• A $110 million increase in fee revenues primarily due to higher volumes in the Marcellus Shale, including new volumes on our recently acquired gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses; higher volumes in the western deepwater Gulf of Mexico, including higher volumes on our Perdido Norte natural gas and oil pipelines; and higher volumes in the Piceance basin.

• A $31 million increase in natural gas transportation revenues associated with gas pipeline expansion projects placed into service in 2011 and 2012.

• Marketing revenues are comparable primarily due to a significant decrease in NGL prices, offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities.

Segment costs and expenses increased $37 million, including:

• A $69 million increase in operating costs including higher depreciation and amortization of assets and intangibles, along with maintenance costs associated with assets acquired in 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.

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Management’s Discussion and Analysis (Continued)

• A $59 million increase in general and administrative expenses including $22 million of Caiman and Laser acquisition and transition-related costs, as well as increases in information technology costs and employee-related expenses driven by general growth within our business operations.

• A $45 million increase in marketing purchases primarily due to higher NGL and crude volumes, as well as new volumes from natural gas marketing activities, partially offset by significantly lower average NGL prices. The changes in natural gas marketing purchases are offset by similar changes in natural gas marketing revenues and resulted in insignificant margins in 2012.

• A $35 million unfavorable change in Other (income) expense—net is primarily due to a $15 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 $114 million decrease in costs associated with our equity NGLs primarily due to a 36 percent decrease in average natural gas prices.

• A $48 million decrease in system management gas costs from our gas pipeline businesses (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 $96 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices.

• A $69 million increase in operating costs as previously discussed.

• A $59 million increase in general and administrative expenses as previously discussed.

• A $48 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 $35 million unfavorable change in Other (income) expense—net is primarily due to a $15 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 $14 million decrease in equity earnings primarily due to $11 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; $8 million lower Aux Sable equity earnings primarily due to lower NGL margins; and $8 million lower Discovery equity earnings primarily due to lower NGL margins and volumes.

• A $110 million increase in fee revenues as previously discussed.

• A $31 million increase in natural gas transportation revenues as previously discussed.

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Management’s Discussion and Analysis (Continued)

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 (RGP 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.

Gulf Olefins Production Facilities

In October 2012, WPZ agreed to acquire our 83.3 percent interest and operatorship of the olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf region. Along with ethane, propane and ethylene, the Geismar facility also produces propylene, butadiene and DAC. The transaction is expected to close in November 2012.

Overview of Nine Months Ended September 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.

Hurricane Isaac Impacts Geismar

During third-quarter 2012, we experienced olefin production downtime at our Geismar facility as a result of Hurricane Isaac, as well as damage to a cracking furnace upon start-up following the hurricane. We estimate that these events reduced our segment profit by approximately $9 million to $13 million in third-quarter 2012. We expect the furnace repair to be completed in fourth-quarter 2012 with an insignificant impact to segment profit. We have adjusted equipment upgrade schedules to mitigate reduced olefin production volumes while the furnace is not in service.

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 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 product sales volumes to be comparable or increase over 2011 levels.

Allocation of capital to projects

We expect to spend $625 million to $725 million in 2012 on capital projects. The major expansion projects include:

43

Management’s Discussion and Analysis (Continued)

• 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. The expansion project is part of the facilities being acquired by WPZ and is expected to be completed 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.

• We have signed a long-term agreement to provide gas processing to a producer in Canada’s oils sands near Fort McMurray, Alberta. To support the new agreement, we plan to build a new liquids extraction plant, supporting facilities and an extension of the Boreal Pipeline to enable transportation of the NGL/olefins mixture to our Redwater facility. The NGL/olefins recovered are initially expected to be approximately 12,000 bbls/d by mid-2015. The NGL/olefins mixture will be fractionated at our Redwater facilities into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate. To mitigate the ethane price risk associated with this deal, we have a long-term supply agreement with a third party customer.

Period-Over-Period Operating Results

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
	(Millions)
Segment revenues	$	231	$	326	$	847	$	989
Segment profit	$	72	$	73	$	243	$	219

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

Segment revenues decreased primarily due to:

• $28 million lower propylene product sales revenues related to the RGP splitter due to 35 percent lower average per-unit sales prices and 44 percent lower sales volumes. The lower average per-unit sales prices resulted from general decreases in commodity pricing. The lower sales volumes were a result of lower production due to third party feedstock constraints that we experienced in July due to an unexpected outage and late-August through September due to Hurricane Isaac.

• $24 million lower ethylene product sales revenues due to 16 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. The lower sales volumes were a result of reduced production due to Hurricane Isaac.

• $24 million lower NGL product sales revenues due to 30 percent lower average per-unit sales prices and slightly lower sales volumes.

44

Management’s Discussion and Analysis (Continued)

• $9 million lower Canadian propylene product sales revenues primarily due to 40 percent lower average per-unit sales prices, partially offset by 10 percent higher sales volumes.

• $8 million lower butadiene product sales revenues primarily due to 48 percent lower average per-unit sales prices.

Segment costs and expenses decreased $94 million primarily due to:

• $50 million lower ethylene feedstock costs resulting from 50 percent lower average per-unit feedstock costs.

• $32 million lower propylene feedstock costs resulting from 52 percent lower average per-unit feedstock costs and 18 percent lower sales volumes.

• $13 million lower NGL feedstock costs resulting from 39 percent lower average per-unit feedstock costs and slightly lower sales volumes.

Segment profit remained consistent primarily due to:

• $26 million higher Geismar ethylene product margins due to 80 percent higher average per-unit margins.

• $11 million lower Canadian NGL product margins resulting from 27 percent lower average per-unit margins.

• $8 million lower Canadian propylene product margins from 43 percent lower average per-unit margins on higher sales volumes.

• $6 million lower Geismar butadiene product margins from 47 percent lower average per-unit margins.

Nine months ended September 30, 2012 vs. nine months ended September 30, 2011

Segment revenues decreased primarily due to:

• $44 million lower NGL product sales revenues primarily due to 20 percent lower average per-unit sales prices.

• $43 million lower propylene product sales revenues primarily due to 22 percent lower average per-unit sales prices, partially offset by 8 percent higher sales volumes.

• $33 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.

• $31 million lower ethylene product sales revenues primarily due to 9 percent lower average per-unit sales prices.

Segment costs and expenses decreased $166 million primarily due to:

• $87 million lower ethylene feedstock costs resulting from 33 percent lower average per-unit feedstock costs.

• $31 million lower propylene feedstock costs resulting from 23 percent lower average per-unit feedstock costs, partially offset by 8 percent higher sales volumes.

45

Management’s Discussion and Analysis (Continued)

• $31 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.

• $23 million lower NGL feedstock costs resulting from 24 percent lower average per-unit feedstock costs.

These decreases were partially offset by $9 million increased operating and maintenance costs, including depreciation.

Segment profit increased primarily due to:

• $56 million higher Geismar ethylene product sales margins resulting primarily from 53 percent higher average per-unit margins.

• $7 million higher Geismar DAC product sales margins resulting from 91 percent higher average per-unit margins.

These increases were partially offset by $21 million lower Canadian NGL product margins primarily due to 16 percent lower average per-unit margins, $11 million lower Canadian propylene product margins primarily due to 27 percent lower average per-unit margins on higher sales volumes, and $9 million higher operating and maintenance costs.

Other

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

Period-Over-Period Operating Results

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
	(Millions)
Segment revenues	$	7	$	6	$	20	$	19
Segment profit	$	1	$	1	$	61	$	23

Nine months ended September 30, 2012 vs. nine months ended September 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.)

46

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 has reduced the expected level of operating cash flows from certain of our businesses in 2012. The downward trend of per-unit NGL margins has leveled off during third quarter 2012 and we anticipate a modest level of improvement through the end of the year. 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 $5.1 billion and $5.5 billion in 2012, excluding WPZ equity issued in 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 $465 million and $545 million. Expansion capital, which is generally more discretionary to fund projects in order to grow our business, is expected to total between $4.7 billion and $5 billion. See Results of Operations – Segments, Williams Partners and Midstream Canada & Olefins for discussions describing the general nature of these investments. In addition, we retain the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

• 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 revolvers, and Williams and WPZ debt and/or 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 $1.95 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 revolver capacity.

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.

47

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 revolvers. Additional sources of liquidity, if needed, include bank financings, proceeds from the issuance of 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 revolver, 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.

			September 30, 2012
Available Liquidity	Expiration		WPZ		WMB			Total
			(Millions)
Cash and cash equivalents			$	368	$	628	(1)	$	996
Capacity available under our $900 million revolver (2)		June 3, 2016				900			900
Capacity available to WPZ under its $2.4 billion revolver (3)		June 3, 2016		2,400					2,400
			$	2,768	$	1,528		$	4,296

(1) Includes $565 million of cash and cash equivalents held primarily by certain international entities, that we intend to utilize to fund growth in our Canadian midstream operations and therefore, 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 September 30, 2012, we are in compliance with the financial covenants associated with this revolver.

(3) In September 2012, WPZ amended its existing $2 billion five-year revolver to increase the aggregate commitments by $400 million. At September 30, 2012, WPZ is in compliance with the financial covenants associated with the WPZ revolver. The WPZ revolver is only available to WPZ, Transco and Northwest Pipeline as co-borrowers.

In addition to the revolvers listed above, we have issued letters of credit totaling $24 million as of September 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.

Debt Offerings

In August 2012, WPZ completed a public offering of $750 million of its 3.35 percent senior unsecured notes due in 2022. WPZ used the $745 million net proceeds to repay outstanding borrowings under the WPZ revolver and for general partnership purposes.

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Management’s Discussion and Analysis (Continued)

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. These proceeds were used to repay Transco’s $325 million 8.875 percent notes and for general corporate purposes, including capital expenditures.

Equity Offerings

In August 2012, WPZ completed an equity issuance of 8,500,000 common units representing limited partner interests in them at a price of $51.43 per unit. Subsequently, WPZ sold an additional 1,275,000 common units for $51.43 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds of $488 million were used to repay outstanding borrowings under the WPZ revolver and for general partnership purposes.

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 10,000,000 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 7,000,000 common units representing limited partner interests in them at a price of $62.81 per unit. In February 2012, WPZ sold an additional 1,050,000 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 Laser Acquisition 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

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Management’s Discussion and Analysis (Continued)

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.

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 September 30, 2012, we estimate that a downgrade to a rating below investment grade for us or WPZ could require us to post up to $47 million or $400 million, respectively, in additional collateral with third parties.

Sources (Uses) of Cash

	Nine months ended September 30,
	2012			2011
	(Millions)
Net cash provided (used) by:
Operating activities	$	1,289		$	2,352
Financing activities		2,498			(163	)
Investing activities		(3,680	)		(1,988	)
Increase (decrease) in cash and cash equivalents	$	107		$	201

Operating activities

Our net cash provided by operating activities for the nine months ended September 30, 2012, decreased $1,063 million from the same period in 2011 largely due to the absence of cash flows from our former exploration and production business and lower operating income.

50

Management’s Discussion and Analysis (Continued)

Financing activities

Significant transactions include:

• $745 million net proceeds received from WPZ’s August 2012 public offering of $750 million of senior unsecured notes due 2022;

• $395 million net proceeds received from Transco’s July 2012 issuance of $400 million of senior unsecured notes;

• $488 million net proceeds received from WPZ’s third quarter 2012 equity offering;

• $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;

• $460 million received from WPZ revolver borrowings used for general partnership purposes, including capital expenditures in third quarter 2012;

• $500 million received from WPZ revolver borrowings used for capital expenditures and general partnership purposes in second quarter 2012;

• $805 million of WPZ revolver borrowings paid during third quarter 2012;

• $325 million paid to retire Transco’s 8.875 percent notes that matured in July 2012;

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

• We paid $538 million in 2012 and $309 million in 2011 of quarterly dividends on common stock;

• We paid $284 million in 2012 and $159 million in 2011 of dividends and distributions to noncontrolling interests;

• $375 million received from Transco’s issuance of senior unsecured notes in August 2011;

• $300 million paid to retire Transco’s senior unsecured notes that matured in August 2011;

• $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 previous $2 billion revolver at its inception in June 2011.

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 Laser Acquisition 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;

• Contributions to our equity method investments were $282 million and $150 million for 2012 and 2011, respectively;

• Capital expenditures totaled $1,652 million and $1,833 million for 2012 and 2011, respectively.

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Management’s Discussion and Analysis (Continued)

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 nine months of 2012.

Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of NGLs and natural gas, 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 limited 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 September 30, 2012 and December 31, 2011. The value-at-risk for contracts held for trading purposes was zero at September 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

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The fair value of our nontrading derivatives was a net asset of $16 million at September 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 $1 million at September 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 $15 million at September 30, 2012, and 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.

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.

Third-Quarter 2012 Changes in Internal Controls

There have been no changes during the third 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 August 2012, we settled 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	—	Third Supplemental Indenture (including Form of 3.35% Senior Notes due 2022), dated as of August 14, 2012, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 14, 2012 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 10.1	—	Commitment Increase and First Amendment Agreement, dated as of September 25, 2012, by and among Williams Partners L.P., Northwest Pipeline GP and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, the Issuing Banks, and Citibank N.A., as administrative agent (filed on September 27, 2012 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
*Exhibit 10.2	—	Consulting Agreement and Release dated September 17, 2012, between The Williams Companies, Inc. and Phillip D. Wright.
*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.

57

Exhibit No.		Description
*Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase.
*Exhibit 101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase.

* Filed herewith.

** Furnished herewith.

58

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)

October 31, 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	—	Third Supplemental Indenture (including Form of 3.35% Senior Notes due 2022), dated as of August 14, 2012, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 14, 2012 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 10.1	—	Commitment Increase and First Amendment Agreement, dated as of September 25, 2012, by and among Williams Partners L.P., Northwest Pipeline GP and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, the Issuing Banks, and Citibank N.A., as administrative agent (filed on September 27, 2012 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
*Exhibit 10.2	—	Consulting Agreement and Release dated September 17, 2012, between The Williams Companies, Inc. and Phillip D. Wright.
* 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 No.		Description
*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.