UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2014

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	74172-0172
(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. YesþNo¨

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).þYes¨No

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes¨Noþ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Shares Outstanding at April 28, 2014
Common Stock, $1 par value	685,518,456

The Williams Companies, Inc.

Index

	Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Income – Three Months Ended March 31, 2014 and 2013	6
Consolidated Statement of Comprehensive Income – Three Months Ended March 31, 2014 and 2013	7
Consolidated Balance Sheet – March 31, 2014 and December 31, 2013	8
Consolidated Statement of Changes in Equity – Three Months Ended March 31, 2014	9
Consolidated Statement of Cash Flows – Three Months Ended March 31, 2014 and 2013	10
Notes to Consolidated Financial Statements	11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3. Quantitative and Qualitative Disclosures About Market Risk	47
Item 4. Controls and Procedures	48
Part II. Other Information	48
Item 1. Legal Proceedings	48
Item 6. Exhibits	50

Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions, and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “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;

• Natural gas, natural gas liquids, and olefins prices, supply and demand;

1

• Demand for our services.

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, and volatility of prices;

• Inflation, interest rates, fluctuation in foreign exchange rates, 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 and the effects of competition;

• Whether we are able to successfully identify, evaluate and execute investment opportunities;

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

• Development of alternative energy sources;

• The impact of operational and development hazards and unforeseen interruptions;

• Costs of, changes in, or the results of laws, government regulations (including safety and environmental regulations), 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 financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of capital;

• The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;

• Risks associated with weather and natural phenomena, including climate conditions;

• Acts of terrorism, including cybersecurity threats and related disruptions; and

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

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

2

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, 2013.

3

DEFINITIONS

The following is a listing of certain abbreviations, acronyms and other industry terminology used throughout this Form 10-Q.

Measurements:

Barrel: One barrel of petroleum products that equals 42 U.S. gallons

Bcf : One billion cubic feet of natural gas

Bcf/d: One billion cubic feet of natural gas per day

British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree

Fahrenheit

Dekatherms (Dth): A unit of energy equal to one million British thermal units

Mbbls/d: One thousand barrels per day

Mdth/d: One thousand dekatherms per day

MMcf/d: One million cubic feet per day

Consolidated Entities:

Constitution: Constitution Pipeline Company, LLC

Gulfstar One: Gulfstar One LLC

Northwest Pipeline: Northwest Pipeline LLC

Transco: Transcontinental Gas Pipe Line Company, LLC

WPZ: Williams Partners L.P.

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which we account

for as an equity investment, including principally the following:

Access GP: Access Midstream Partners GP, L.L.C.

Access Midstream Partners: Access GP and ACMP

ACMP: Access Midstream Partners, L.P.

Aux Sable: Aux Sable Liquid Products LP

Bluegrass Pipeline: Bluegrass Pipeline Company LLC

Caiman II: Caiman Energy II, LLC

Discovery: Discovery Producer Services LLC

Gulfstream: Gulfstream Natural Gas System, L.L.C.

Laurel Mountain: Laurel Mountain Midstream, LLC

Moss Lake: Moss Lake Fractionation LLC and Moss Lake LPG Terminal LLC

OPPL: Overland Pass Pipeline Company LLC

Government and Regulatory:

EPA: Environmental Protection Agency

FERC: Federal Energy Regulatory Commission

4

Other:

B/B Splitter: Butylene/Butane splitter

RGP Splitter: Refinery grade propylene splitter

IDR: Incentive distribution right

NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are

used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications

NGL margins:NGL revenues less Btu replacement cost, plant fuel, transportation, and fractionation

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PART I – FINANCIAL INFORMATION

The Williams Companies, Inc.

Consolidated Statement of Income

(Unaudited)

	Three months ended    March 31,
	2014			2013
	(Millions, except per-share amounts)
Revenues:
Service revenues	$	819		$	706
Product sales	930			1,104
Total revenues	1,749			1,810
Costs and expenses:
Product costs	769			790
Operating and maintenance expenses	298			260
Depreciation and amortization expenses	214			201
Selling, general, and administrative expenses	150			132
Net insurance recoveries – Geismar Incident	(119		)	—
Other (income) expense – net	17			1
Total costs and expenses	1,329			1,384
Operating income (loss)	420			426
Equity earnings (losses)	(48		)	18
Interest incurred	(169		)	(152		)
Interest capitalized	29			24
Other investing income – net	14			13
Other income (expense) – net	1			(2		)
Income (loss) from continuing operations before income taxes	247			327
Provision (benefit) for income taxes	51			96
Income (loss) from continuing operations	196			231
Income (loss) from discontinued operations	—			(1		)
Net income (loss)	196			230
Less: Net income attributable to noncontrolling interests	56			69
Net income (loss) attributable to The Williams Companies, Inc.	$	140		$	161
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations	$	140		$	162
Income (loss) from discontinued operations	—			(1		)
Net income (loss)	$	140		$	161
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	.20		$	.24
Income (loss) from discontinued operations	—			—
Net income (loss)	$	.20		$	.24
Weighted-average shares (thousands)	684,773			682,052
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	.20		$	.23
Income (loss) from discontinued operations	—			—
Net income (loss)	$	.20		$	.23
Weighted-average shares (thousands)	688,904			687,143
Cash dividends declared per common share	$	.4025		$	.33875

See accompanying notes.

6

The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income

(Unaudited)

	Three months ended    March 31,
	2014			2013
	(Millions)
Net income (loss)	$	196		$	230
Other comprehensive income (loss):
Foreign currency translation adjustments, net of taxes of $1 in 2014	(44		)	(21		)
Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit cost, net of taxes of $1 in 2014	(1		)	(1		)
Amortization of actuarial (gain) loss included in net periodic benefit cost, net of taxes of ($3) and ($6) in 2014 and 2013, respectively	6			10
Other comprehensive income (loss)	(39		)	(12		)
Comprehensive income (loss)	157			218
Less: Comprehensive income (loss) attributable to noncontrolling interests	56			69
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	101		$	149

See accompanying notes.

7

The Williams Companies, Inc.

Consolidated Balance Sheet

(Unaudited)

	March 31, 2014			December 31, 2013
	(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	1,064		$	681
Accounts and notes receivable, net:
Trade and other	629			600
Income tax receivable	29			74
Deferred income tax asset	141			27
Inventories	222			194
Other current assets and deferred charges	93			107
Total current assets	2,178			1,683
Investments	4,520			4,360
Property, plant and equipment, at cost	26,484			25,823
Accumulated depreciation and amortization	(7,773		)	(7,613		)
Property, plant and equipment – net	18,711			18,210
Goodwill	646			646
Other intangible assets	1,632			1,644
Regulatory assets, deferred charges, and other	619			599
Total assets	$	28,306		$	27,142
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,094		$	960
Accrued liabilities	704			797
Commercial paper	—			225
Long-term debt due within one year	751			1
Total current liabilities	2,549			1,983
Long-term debt	12,099			11,353
Deferred income taxes	3,528			3,529
Other noncurrent liabilities	1,413			1,356
Contingent liabilities (Note 11)
Equity:
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 720 million shares issued at March 31, 2014 and 718 million shares issued at December 31, 2013)	720			718
Capital in excess of par value	11,545			11,599
Retained deficit	(6,385		)	(6,248		)
Accumulated other comprehensive income (loss)	(223		)	(164		)
Treasury stock, at cost (35 million shares of common stock)	(1,041		)	(1,041		)
Total stockholders’ equity	4,616			4,864
Noncontrolling interests in consolidated subsidiaries	4,101			4,057
Total equity	8,717			8,921
Total liabilities and equity	$	28,306		$	27,142

See accompanying notes.

8

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 Equity
	(Millions)
Balance – December 31, 2013	$	718	$	11,599		$	(6,248	)	$	(164	)	$	(1,041	)	$	4,864		$	4,057		$	8,921
Net income (loss)	—		—			140			—			—			140			56			196
Other comprehensive income (loss)	—		—			—			(39		)	—			(39		)	—			(39		)
Cash dividends – common stock	—		—			(276		)	—			—			(276		)	—			(276		)
Dividends and distributions to noncontrolling interests	—		—			—			—			—			—			(147		)	(147		)
Stock-based compensation and related common stock issuances, net of tax	2		21			—			—			—			23			—			23
Changes in ownership of consolidated subsidiaries, net	—		(72		)	—			(20		)	—			(92		)	135			43
Contributions from noncontrolling interests	—		—			—			—			—			—			63			63
Deconsolidation of Bluegrass Pipeline (Note 2)	—		—			—			—			—			—			(63		)	(63		)
Other	—		(3		)	(1		)	—			—			(4		)	—			(4		)
Balance – March 31, 2014	$	720	$	11,545		$	(6,385	)	$	(223	)	$	(1,041	)	$	4,616		$	4,101		$	8,717

See accompanying notes.

9

The Williams Companies, Inc.

Consolidated Statement of Cash Flows

(Unaudited)

	Three months ended    March 31,
	2014			2013
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	196		$	230
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	214			201
Provision (benefit) for deferred income taxes	(96		)	103
Amortization of stock-based awards	11			9
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	16			(72		)
Inventories	(27		)	(13		)
Other current assets and deferred charges	22			11
Accounts payable	(16		)	6
Accrued liabilities	67			(25		)
Other, including changes in noncurrent assets and liabilities	59			45
Net cash provided (used) by operating activities	446			495
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	(225		)	—
Proceeds from long-term debt	1,496			770
Payments of long-term debt	—			(895		)
Proceeds from issuance of common stock	14			7
Proceeds from sale of limited partner units of consolidated partnership	—			617
Dividends paid	(276		)	(231		)
Dividends and distributions paid to noncontrolling interests	(147		)	(105		)
Contributions from noncontrolling interests	63			2
Other – net	4			11
Net cash provided (used) by financing activities	929			176
INVESTING ACTIVITIES:
Capital expenditures (1)	(793		)	(713		)
Purchases of and contributions to equity-method investments	(228		)	(93		)
Other – net	29			(2		)
Net cash provided (used) by investing activities	(992		)	(808		)
Increase (decrease) in cash and cash equivalents	383			(137		)
Cash and cash equivalents at beginning of period	681			839
Cash and cash equivalents at end of period	$	1,064		$	702
_________
(1) Increases to property, plant, and equipment	$	(840	)	$	(732	)
Changes in related accounts payable and accrued liabilities	47			19
Capital expenditures	$	(793	)	$	(713	)

See accompanying notes.

10

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 for the year ended December 31, 2013, in our Annual Report on Form 10-K. 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, Williams NGL & Petchem Services, and Access Midstream Partners reportable 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 midstream businesses. The gas pipeline businesses primarily consist of two interstate natural gas pipelines, which are Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (Northwest Pipeline), a 50 percent equity investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), and a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity). 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 an NGL fractionator and storage facilities near Conway, Kansas as well as an NGL light-feed olefins cracker in Geismar, Louisiana, along with associated ethane and propane pipelines, a refinery grade splitter in Louisiana, an oil sands offgas processing plant located near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and butylene/butane splitter facility at Redwater, Alberta.

Williams NGL & Petchem Services consists primarily of a 50 percent equity investment in Bluegrass Pipeline Company LLC (Bluegrass Pipeline) and certain domestic olefins pipeline assets and Canadian facilities under development.

Access Midstream Partners consists of our equity investment in Access Midstream Partners, L.P. (ACMP). As of March 31, 2014, this investment includes an indirect 50 percent interest in Access Midstream Partners, GP, L.L.C. (Access GP), including incentive distribution rights, and a 23 percent limited partner interest in ACMP. ACMP is a publicly-traded master limited partnership that provides gathering, treating, and compression services to producers under long-term, fee-based contracts. Access GP is the general partner of ACMP.

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

11

Notes (Continued)

Basis of Presentation

In February 2014, we contributed certain Canadian operations to WPZ (Canada Dropdown) for total consideration of $25 million of cash from WPZ (subject to certain closing adjustments), 25,577,521 WPZ Class D limited-partner units, and an increase in the capital account of its general partner to allow us to maintain our 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units. All Class D units outstanding will be convertible to common units beginning in the first quarter of 2016. The contribution agreement governing the Canada Dropdown provides that WPZ can issue additional Class D units to us on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions. These operations were previously reported within the Williams NGL & Petchem Services segment, but are now reported within Williams Partners. Prior period segment disclosures have been recast for this transaction.

Consolidated master limited partnership

Following the transaction discussed above, as of March 31, 2014, 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.

WPZ is self-funding and maintains separate lines of bank credit and cash management accounts and also has a commercial paper program. (See Note 8 – Debt and Banking Arrangements.) 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.

Discontinued operations

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

Note 2 – Variable Interest Entities

Consolidated VIEs

As of March 31, 2014, we consolidate the following variable interest entities (VIEs):

Gulfstar One

WPZ owns a 51 percent interest in Gulfstar One LLC (Gulfstar One), a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Gulfstar One’s economic performance. WPZ, as construction agent for Gulfstar One, designed, constructed, and is installing 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. The project is expected to be in service in the third quarter of 2014. WPZ has received certain advance payments from the producer customers and is committed to the producer customers to construct this system. The current estimate of the total remaining construction costs is less than $250 million, which we expect will be funded by us and our partner. The producer customers will be responsible for the firm price of building the facilities if they do not develop the offshore oil and gas fields to be connected to Gulfstar One.

In December 2013, WPZ committed an additional amount to Gulfstar One to fund an expansion of the system that will provide production handling, gathering, and processing services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico. The expansion project is expected to be in service in the first quarter of 2016. The current estimate of the total remaining construction costs of the Gunflint project is less than $134 million. The other equity partner has an option to participate in the funding of the expansion project on a proportional basis.

Constitution

WPZ owns a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its firm transportation contracts, is a VIE. WPZ is the primary beneficiary because it has the power to direct the

12

Notes (Continued)

activities that most significantly impact Constitution’s economic performance. WPZ, as construction agent for Constitution, is building a pipeline connecting our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. WPZ plans to place the project in service in late 2015 to 2016 and estimates the total remaining construction costs of the project to be less than $600 million, which will be funded with capital contributions from WPZ and the other equity partners, proportional to ownership interest.

The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of these VIEs, which are joint projects in the development and construction phase.

	March 31, 2014			December 31, 2013 (1)			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	36		$	122		Cash and cash equivalents
Accounts receivable	10			—			Accounts and notes receivable, net
Property, plant and equipment	1,209			1,111			Property, plant and equipment, at cost
Accounts payable	(153		)	(145		)	Accounts payable
Construction retainage	(4		)	(3		)	Accrued liabilities
Current deferred revenue	—			(10		)	Accrued liabilities
Asset retirement obligation	(30		)	—			Other noncurrent liabilities
Noncurrent deferred revenue associated with customer advance payments	(130		)	(115		)	Other noncurrent liabilities

(1) Amounts presented for December 31, 2013, include balances related to Bluegrass Pipeline. See discussion of the subsequent deconsolidation of Bluegrass Pipeline below.

Nonconsolidated VIEs

We have also identified certain interests in VIEs for which we are not the primary beneficiary. These include:

Laurel Mountain

WPZ’s 51 percent-owned equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain) is considered to be a VIE generally due to contractual provisions that transfer certain risks to customers. As decisions about the activities that most significantly impact the economic performance of this entity require a unanimous vote of all members, WPZ is not the primary beneficiary. Our maximum exposure to loss is limited to the carrying value of this investment, which was $482 millionat March 31, 2014.

Caiman II

In the first quarter of 2014, WPZ contributed $119 million to Caiman Energy II, LLC (Caiman II) in exchange for an increased ownership of Caiman II. Following these contributions, WPZ owns a 58 percent interest in Caiman II, which is reported as an equity-method investment. Caiman II is considered to be a VIE because it has insufficient equity to finance the construction stage activities of its 50 percent interest in Blue Racer Midstream LLC, which is expanding the gathering and processing and associated liquids infrastructure serving oil and gas producers in the Utica shale primarily in Ohio and northwest Pennsylvania. WPZ is not the primary beneficiary because it does not have the power to direct the activities of Caiman II that most significantly impact its economic performance. Our maximum exposure to loss is limited to the $500 million of total contributions that we have committed to make inclusive of contributions made to date. At March 31, 2014, the carrying value of our investment in Caiman II was $415 million,which substantially reflects our contributions to that date.

13

Notes (Continued)

Bluegrass Pipeline

The Bluegrass Pipeline is a proposed NGL pipeline that would connect processing facilities in the Marcellus and Utica shale-gas areas in the northeastern United States to growing petrochemical and export markets in the Gulf Coast area of the United States. Bluegrass Pipeline is considered to be a VIE because it has insufficient equity to finance activities during its development stage. As of March 31, 2014, we own a 50 percent equity-method investment interest in Bluegrass Pipeline. From its inception until the first quarter of 2014, we were the primary beneficiary of this entity because we had the power to direct whether the project moved forward and thus we previously consolidated the Bluegrass Pipeline.

On February 16, 2014, we and our partner executed an amendment to the governing documents that removed our power to direct whether the project moved forward. As a result, we were no longer the primary beneficiary as of that date and we deconsolidated the Bluegrass Pipeline and began reporting our 50 percent interest as an equity-method investment. There was no gain or loss recognized upon deconsolidation.

Completion of this project is subject to execution of customer contracts sufficient to support the project. Although discussions with potential customers continue, we have not received sufficient executed customer commitments to date to support the continued development of the project. Considering this and other factors, our management decided in April to discontinue further funding of the project at this time. Given these developments, the capitalized project development costs at the Bluegrass Pipeline entity were written off as of March 31, 2014, and as a result, we have recognized $67 million in related equity losses in the first quarter of 2014. The carrying value of our investment in Bluegrass Pipeline is $1 million at March 31, 2014.

Moss Lake

Our 50 percent-owned equity-method investments in Moss Lake Fractionation LLC and Moss Lake LPG Terminal LLC (collectively referred to as Moss Lake) are considered to be VIEs because they have insufficient equity to finance activities during their development stage. Moss Lake may construct a proposed new large-scale fractionation plant, expand natural gas liquids storage facilities in Louisiana and construct a proposed pipeline connecting these facilities to the Bluegrass Pipeline. Additionally, Moss Lake may construct a proposed new liquefied petroleum gas (LPG) terminal. We are not the primary beneficiary of this entity because we do not have the power to direct the majority of the activities of Moss Lake that most significantly impact its economic performance at this stage. In the first quarter of 2014, we have recognized $4 million in equity losses related to Moss Lake, primarily associated with the underlying write-off of capitalized project development costs at Moss Lake. The carrying value of our investment in Moss Lake is $2 million at March 31, 2014.

Note 3 – Other Income and Expenses

On June 13, 2013, an explosion and fire occurred at WPZ’s Geismar olefins plant. The fire was extinguished on the day of the incident. The incident (Geismar Incident) rendered the facility temporarily inoperable and resulted in significant human, financial and operational effects.

We have substantial insurance coverage for repair and replacement costs, lost production, and additional expenses related to the incident as follows:

• Property damage and business interruption coverage with a combined per-occurrence limit of $500 million and retentions (deductibles) of $10 million per occurrence for property damage and a waiting period of 60 days per occurrence for business interruption;

• General liability coverage with per-occurrence and aggregate annual limits of $610 million and retentions (deductibles) of $2 million per occurrence;

• Workers’ compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence.

14

Notes (Continued)

During the first quarter of 2014, we received $125 million of insurance recoveries related to the Geismar Incident and incurred $6 million of related covered insurable expenses in excess of our retentions (deductibles). These amounts are reflected as a net gain in Net insurance recoveries – Geismar Incident within Costs and expenses in our Consolidated Statement of Income.

Selling, general, and administrative expenses for the first quarter of 2014 includes $19 million of project development costs related to the Bluegrass Pipeline.

Other investing income – net includes $13 million of interest income for each of the three month periods ended March 31, 2013 and 2014 associated with a receivable related to the sale of certain former Venezuela assets.

Note 4 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes from continuing operations includes:

	Three months ended    March 31,
	2014			2013
	(Millions)
Current:
Federal	$	137		$	(11	)
State	5			2
Foreign	2			2
	144			(7		)
Deferred:
Federal	(96		)	82
State	(1		)	13
Foreign	4			8
	(93		)	103
Total provision (benefit)	$	51		$	96

The effective income tax rate for the total provision for the three months ended March 31, 2014, is less than the federal statutory rate primarily due to a tax benefit related to the completion of the Canada Dropdown and the impact of nontaxable noncontrolling interests, partially offset by the effect of state income taxes and taxes on foreign operations.

The effective income tax rate for the total provision for the three months ended March 31, 2013, is less than the federal statutory rate primarily due to the impact of nontaxable noncontrolling interests and taxes on foreign operations, partially offset by the effect of state income taxes.

As a result of closing the Canada Dropdown, $90 million of previously deferred tax liability has been reclassified as a current income tax liability in the first quarter of 2014.

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.

15

Notes (Continued)

Note 5 – Earnings (Loss) Per Common Share from Continuing Operations

	Three months ended    March 31,
	2014		2013
	(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	$	140	$	162
Basic weighted-average shares	684,773		682,052
Effect of dilutive securities:
Nonvested restricted stock units	2,096		2,720
Stock options	2,017		2,187
Convertible debentures	18		184
Diluted weighted-average shares	688,904		687,143
Earnings (loss) per common share from continuing operations:
Basic	$	.20	$	.24
Diluted	$	.20	$	.23

Note 6 – Employee Benefit Plans

Net periodic benefit cost (credit) is as follows:

	Pension Benefits
	Three months ended    March 31,
	2014			2013
	(Millions)
Components of net periodic benefit cost:
Service cost	$	10		$	11
Interest cost	16			13
Expected return on plan assets	(19		)	(15		)
Amortization of net actuarial loss	9			15
Net periodic benefit cost	$	16		$	24

	Other Postretirement Benefits
	Three months ended    March 31,
	2014			2013
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	1		$	1
Interest cost	2			3
Expected return on plan assets	(3		)	(2		)
Amortization of prior service credit	(5		)	(2		)
Amortization of net actuarial loss	—			2
Reclassification to regulatory liability	1			—
Net periodic benefit cost (credit)	$	(4	)	$	2

16

Notes (Continued)

Amortization of prior service credit and net actuarial loss included in net periodic benefitcost (credit) for our other postretirement benefit plans associated with Transco and Northwest Pipeline are recorded to regulatory assets/liabilities instead of other comprehensive income (loss).

Amounts recognized in regulatory assets/liabilities include:

	Three months ended    March 31,
	2014			2013
	(Millions)
Amortization of prior service credit	$	(3	)	$	(1	)
Amortization of net actuarial loss	—			1

During the three months ended March 31, 2014, we contributed $16 million to our pension plans and $2 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $47 million to our pension plans and approximately $6 million to our other postretirement benefit plans in the remainder of 2014.

Note 7 – Inventories

	March 31, 2014		December 31, 2013
	(Millions)
Natural gas liquids, olefins, and natural gas in underground storage	$	141	$	111
Materials, supplies, and other	81		83
	$	222	$	194

Note 8 – Debt and Banking Arrangements

Long-Term Debt

Issuances

On March 4, 2014, WPZ completed a public offering of $1 billion of 4.3 percent senior unsecured notes due 2024 and $500 million of 5.4 percent senior unsecured notes due 2044. WPZ used a portion of the net proceeds to repay amounts outstanding under its commercial paper program and expects to utilize the remainder to fund capital expenditures and for general partnership purposes.

Credit Facilities

Letter of credit capacity under our $1.5 billion and WPZ’s $2.5 billion credit facilities is $700 million and $1.3 billion, respectively. At March 31, 2014, no letters of credit have been issued and no loans are outstanding on these credit facilities. We issued letters of credit totaling $15 million and WPZ issued letters of credit totaling $9 million as of March 31, 2014, under certain bilateral bank agreements.

17

Notes (Continued)

Note 9 – Accumulated Other Comprehensive Income

The following table presents the changes in Accumulated other comprehensive income (loss) by component, net of income taxes:

	Cash Flow Hedges			Foreign Currency Translation			Pension and Other Post Retirement Benefits			Total
	(Millions)
Balance at December 31, 2013	$	(1	)	$	128		$	(291	)	$	(164	)
Other comprehensive income (loss) before reclassifications	—			(44		)	—			(44		)
Amounts reclassified from accumulatedother comprehensive income (loss)	—			—			5			5
Other comprehensive income (loss)	—			(44		)	5			(39		)
Changes in ownership of consolidated subsidiaries, net	—			(20		)	—			(20		)
Balance at March 31, 2014	$	(1	)	$	64		$	(286	)	$	(223	)

Reclassifications out of Accumulated other comprehensive income (loss) are presented in the following table by component for the three months ended March 31, 2014:

Component	Reclassifications			Classification
	(Millions)
Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit cost	$	(2	)	Note 6 – Employee Benefit Plans
Amortization of actuarial (gain) loss included in net periodic benefit cost	9			Note 6 – Employee Benefit Plans
Total pension and other postretirement benefits, before income taxes	7
Income tax benefit	(2		)	Provision (benefit) for income taxes
Reclassifications during the period	$	5

18

Notes (Continued)

Note 10 – Fair Value Measurements and Guarantees

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, commercial paper, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.

							Fair Value Measurements Using
	Carrying Amount			Fair Value			Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at March 31, 2014:
Measured on a recurring basis:
ARO Trust investments	$	45		$	45		$	45	$	—		$	—
Energy derivatives assets not designated as hedging instruments	3			3			—		—			3
Energy derivatives liabilities not designated as hedging instruments	(2		)	(2		)	—		—			(2		)
Additional disclosures:
Notes receivable and other	75			130			2		6			122
Long-term debt, including current portion (1)	(12,849		)	(13,790		)	—		(13,790		)	—
Guarantee	(31		)	(28		)	—		(28		)	—
Assets (liabilities) at December 31, 2013:
Measured on a recurring basis:
ARO Trust investments	$	33		$	33		$	33	$	—		$	—
Energy derivatives assets not designated as hedging instruments	3			3			—		—			3
Energy derivatives liabilities not designated as hedging instruments	(3		)	(3		)	—		(1		)	(2		)
Additional disclosures:
Notes receivable and other	77			140			1		6			133
Long-term debt (1)	(11,353		)	(11,971		)	—		(11,971		)	—
Guarantee	(32		)	(29		)	—		(29		)	—

(1) Excludes capital leases

Fair Value Methods

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

Assets and liabilities measured at fair value on a recurring basis

ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its 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 prices in an active market, 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 of physical forwards, futures, and swaps that are measured at fair value on a recurring

19

Notes (Continued)

basis. 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 assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in Accrued liabilities and Other noncurrent liabilities in the Consolidated Balance Sheet.

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 three months ended March 31, 2014 or 2013.

Additional fair value disclosures

Notes receivable and other: Notes receivable and other includes a receivable related to the sale of certain former

Venezuela assets. The disclosed fair value of this receivable is determined by an income 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, future probabilities of default, our likelihood of using arbitration if the counterparty does not perform, and discount rates. We determined the fair value of the receivable to be $87 million at March 31, 2014. The carrying value of this receivable is $32 million at March 31, 2014. The current and noncurrent portions are reported in Accounts and notes receivable, net and Regulatory assets, deferred charges, and other, respectively, in the Consolidated Balance Sheet.

Notes receivable and other also includes a receivable from our former affiliate, WPX Energy, Inc (WPX) (see Note 11 – Contingent Liabilities) and other notes receivable. The disclosed fair value of these receivables is primarily 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, net 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.

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 $35 million at March 31, 2014 and December 31, 2013. Our exposure declines systematically throughout the remaining term of WilTel’s obligation.

20

Notes (Continued)

We have provided guarantees in the event of nonpayment by our previously owned subsidiary, WPX, on certain contracts, primarily a natural gas purchase contract extending through 2023. We estimate the maximum undiscounted potential future payment obligation under these remaining guarantees is approximately $59 million at March 31, 2014. Our recorded liability for these guarantees, which considers our estimate of the fair value of the guarantees, is insignificant.

Note 11 – 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 accrued asset and liability balances associated with these matters, and as a result, have an indirect exposure to future developments in these matters.

Issues resulting from California energy crisis

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

Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, WPX continued to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. On April 24, 2014, the FERC approved a settlement among the California utilities, WPX, and us which resolves WPX’s collection of accrued interest from counterparties as well as WPX’s payment of accrued interest on refund amounts. The settlement will 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.

Reporting of natural gas-related information to trade publications

Direct and indirect purchasers of natural gas in various states filed class actions against WPX and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues.

In 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. The plaintiffs appealed the court’s ruling and on April 10, 2013, the Ninth Circuit Court of Appeals reversed the district court and remanded the cases to the district court to permit the plaintiffs to pursue their state antitrust claims for natural gas sales that were not subject to FERC jurisdiction under the Natural Gas Act. On August 26, 2013, WPX and the other defendants filed their petition for a writ of certiorari with the U.S. Supreme Court. Because of the uncertainty around the remaining 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

Geismar Incident

As a result of the previously discussed Geismar Incident, there were two fatalities, and numerous individuals (including employees and contractors) reported injuries, which varied from minor to serious. WPZ is cooperating with the Chemical Safety Board and the U.S. Environmental Protection Agency (EPA) regarding their investigations of the Geismar Incident. On October 21, 2013, the EPA issued an Inspection Report pursuant to the Clean Air Act’s Risk

21

Notes (Continued)

Management Program following its inspection of the facility on June 24 through 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. We and the EPA continue to discuss such preliminary determinations, and the EPA could issue penalties pertaining to final determinations. On December 11, 2013, the Occupational Safety and Health Administration (OSHA) issued citations in connection with its investigation of the June 13, 2013 incident, which included a Notice of Penalty for $99,000. Although we and OSHA continue settlement negotiations, we are contesting the citations. On June 25, 2013, OSHA commenced a second inspection pursuant to its Refinery and Chemical National Emphasis Program (NEP). OSHA has not issued any citation to WPZ in connection with this NEP inspection. There is a six month statute of limitations for violation of the Occupational Safety and Health Act of 1970 or regulations promulgated under such act. On June 28, 2013, the Louisiana Department of Environmental Quality (LDEQ) issued a Consolidated Compliance Order & Notice of Potential Penalty to Williams Olefins, L.L.C. that consolidates claims of unpermitted emissions and other deviations under the Clean Air Act that the parties had been negotiating since 2010 and alleged unpermitted emissions arising from the Geismar Incident. Negotiations with the LDEQ are ongoing. Any potential fines and penalties from these agencies would not be covered by our insurance policy. Additionally, multiple lawsuits, including class actions for alleged offsite impacts, property damage, and personal injury, have been filed against various of our subsidiaries.

Due to the ongoing investigation into the cause of the incident, and the limited information available associated with the filed lawsuits, which do not specify any amounts for claimed damages, we cannot reasonably estimate a range of potential loss related to these contingencies at this time.

Gulf Liquids litigation

Gulf Liquids, one of our subsidiaries, 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.  From May through October 2007, the court entered seven post-trial orders in the case 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 certain damages against Gulf Liquids in favor of Gulsby and Gulsby-Bay. Gulf Liquids, Gulsby, Gulsby-Bay, Bay Ltd., and NAICO appealed the judgment. In February 2009, we settled with Gulsby-Bay and Bay. On February 17, 2011, the Texas Court of Appeals upheld the dismissals of the tort and punitive damages claims and 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 to trial court. Trial is set for October 14, 2014.  In 2006, we accrued a charge, and related interest, for our estimate of probable loss associated with the initial adverse verdict.  From 2008 through 2011, the amount accrued was reduced based on subsequent judgments and settlement payments.  As of March 31, 2014, we have a remaining accrued liability of $13 million associated with the litigation.

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 2011, we and FHRA settled the James West claim. We and FHRA subsequently filed motions for summary judgment on the other’s claims. On November 5, 2013, the court ruled that the applicable statute of limitations bars all

22

Notes (Continued)

FHRA’s claims against us and dismissed those claims with prejudice. FHRA has asked the court to reconsider and clarify its ruling, and we anticipate that FHRA will appeal the court’s decision.

We currently estimate that our reasonably possible loss exposure in this matter could range from an insignificant amount up to $32 million, although uncertainties inherent in the litigation process, expert evaluations, and jury dynamics might cause our exposure to exceed that amount.

Independent of the litigation matter described in the preceding paragraphs, the Alaska Department of Environmental Conservation (ADEC) indicated that it views FHRA and us as responsible parties. During the first quarter of 2013 and again on December 23, 2013, ADEC informed FHRA and us that ADEC intends to enter a compliance order to address the environmental remediation of sulfolane and other possible contaminants including cleanup work outside the refinery’s boundaries to be performed in 2014. In addition, ADEC will seek from each of FHRA and us an adequate financial performance guarantee for the benefit of ADEC. On March 6, 2014, the State of Alaska filed suit against FHRA and us in state court in Fairbanks seeking injunctive relief and damages in connection with the sulfolane contamination. Due to the ongoing assessment of the level and extent of sulfolane contamination and the ultimate cost of remediation and division of costs among the potentially responsible parties, we are unable to estimate a range of exposure at this time.

Transco 2012 rate case

On August 31, 2012, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceedings. The new rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, Transco filed a stipulation and agreement with the FERC proposing to resolve all issues in this proceeding without the need for a hearing (Agreement). On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement became effective March 1, 2014. As of March 31, 2014, Accounts Payable includes$118 million for rate refunds that were subsequently paid on April 18, 2014.

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 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 March 31, 2014, we have accrued liabilities totaling $46 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered and the final cleanup standards mandated by the EPA and other governmental authorities.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, one hour nitrogen dioxide emission limits, and new air quality standards impacting storage vessels, pressure valves, and compressors. 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.

23

Notes (Continued)

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 March 31, 2014, we have accrued liabilities of $13 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At March 31, 2014, we have accrued liabilities totaling $7 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 remediation activities at the direction of federal and state environmental authorities and 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 March 31, 2014, 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 March 31, 2014, other than as previously disclosed, we are not aware of any material claims against us involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.

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

Summary

We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued 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.

24

Notes (Continued)

Note 12 – Segment Disclosures

Our reportable segments are Williams Partners, Williams NGL & Petchem Services, and Access Midstream Partners. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, and Basis of Presentation.)

Performance Measurement

We currently evaluate segment operating 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. General corporate expenses represent Selling, general, and administrative expenses that are not allocated to our segments. Intersegment revenues are generally accounted for at current market prices as if the sales were to unaffiliated third parties.

25

Notes (Continued)

The following table reflects the reconciliation of Segment revenues and Segment profit (loss) to Total revenues and Operating income (loss) as reported in the Consolidated Statement of Income and Total assets by reportable segment.

	Williams Partners			Williams NGL & Petchem Services			Access Midstream Partners		Other			Eliminations			Total
	(Millions)
Three months ended March 31, 2014
Segment revenues:
Service revenues
External	$	763		$	—		$	—	$	56		$	—		$	819
Internal	—			—			—		3			(3		)	—
Total service revenues	763			—			—		59			(3		)	819
Product sales
External	930			—			—		—			—			930
Internal	—			—			—		—			—			—
Total product sales	930			—			—		—			—			930
Total revenues	$	1,693		$	—		$	—	$	59		$	(3	)	$	1,749
Segment profit (loss)	$	503		$	(100	)	$	6	$	3					$	412
Less equity earnings (losses)	23			(77		)	6		—						(48		)
Segment operating income (loss)	$	480		$	(23	)	$	—	$	3					460
General corporate expenses															(40		)
Operating income (loss)															$	420
Three months ended March 31, 2013
Segment revenues:
Service revenues
External	$	702		$	—		$	—	$	4		$	—		$	706
Internal	—			—			—		3			(3		)	—
Total service revenues	702			—			—		7			(3		)	706
Product sales
External	1,104			—			—		—			—			1,104
Internal	—			—			—		—			—			—
Total product sales	1,104			—			—		—			—			1,104
Total revenues	$	1,806		$	—		$	—	$	7		$	(3	)	$	1,810
Segment profit (loss)	$	494		$	(2	)	$	—	$	(5	)				$	487
Less:
Equity earnings (losses)	18			—			—		—						18
Income (loss) from investments	(1		)	—			—		—						(1		)
Segment operating income (loss)	$	477		$	(2	)	$	—	$	(5	)				470
General corporate expenses															(44		)
Operating income (loss)															$	426
March 31, 2014
Total assets	$	24,791		$	378		$	2,136	$	1,459		$	(458	)	$	28,306
December 31, 2013
Total assets	$	23,571		$	486		$	2,161	$	1,359		$	(435	)	$	27,142

26

Notes (Continued)

Note 13 – Subsequent Event

On April 23, 2014, an explosion and fire occurred at WPZ’s natural gas processing facility near Opal, Wyoming. There were no reported injuries or damage to property outside the facility. The facility was immediately shut down and natural gas gathering from surrounding producing areas was temporarily suspended as a result of the incident.

The facility is primarily comprised of five turbo-expander (TXP) cryogenic gas-processing units. Although we have not yet made a full assessment of all plant equipment, the initial visual assessment of damage indicates that the impact was largely limited to the TXP-3 unit. We are inspecting the damaged equipment in cooperation with regulatory authorities and developing preliminary plans to bring the other four units back into service. The capacity of the four undamaged plants is sufficient to handle all of the natural gas currently available to the facility.

We have insurance coverage, subject to retentions (deductibles), for property damage and business interruption that we expect to significantly mitigate the financial effects of the incident.

27

Item 2

Management’s Discussion and Analysis of

Financial Condition and Results of Operations

General

We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas, natural gas liquids, 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, Williams NGL & Petchem Services, and Access Midstream Partners reportable segments. All remaining business activities are included in Other.

Williams Partners

Williams Partners 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. WPZ also owns a 5/6 interest in an olefin production facility, along with a refinery grade propylene splitter and pipelines in the Gulf region, an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and B/B splitter facility at Redwater, Alberta. We produce olefins and NGLs. As of March 31, 2014, 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 Gulf Coast Region, 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 transmission revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

Williams NGL & Petchem Services

Williams NGL & Petchem Services includes certain other domestic olefins pipeline assets, certain Canadian growth projects under development, including a propane dehydrogenation facility and a liquids extraction plant, as well as the proposed Bluegrass Pipeline joint project (see Note 2 – Variable Interest Entities of Notes to Consolidated Financial Statements for more information regarding current period developments). As discussed in Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements, the currently operating Canadian assets contributed to Williams Partners in the first quarter of 2014 and are now presented in the Williams Partners segment. As a result, this segment is currently comprised primarily of projects under development and thus has no operating revenues to date.

Access Midstream Partners

Access Midstream Partners includes our equity method investment in ACMP. As of March 31, 2014, this investment includes a 23 percent limited partner interest in ACMP and a 50 percent indirect interest in Access GP, including incentive distribution rights. ACMP is a publicly traded master limited partnership that owns, operates, develops, and

28

Management’s Discussion and Analysis (Continued)

acquires natural gas gathering systems and other midstream energy assets, which bolsters our position in the Marcellus and Utica shale plays and adds diversity via the Eagle Ford, Haynesville, Barnett, Mid-Continent, and Niobrara areas.

Unless indicated otherwise, the following discussion and analysis of 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 our 2013 Annual Report on Form 10‑K, filed February 26, 2014.

Dividends

In March 2014, we paid a regular quarterly dividend of $0.4025 per share, which was 19 percent higher than the same period last year and 6 percent higher than the prior quarter. Also, consistent with our expectation of receiving increasing cash distributions from our interests in WPZ and ACMP, we expect to increase our dividend on a quarterly basis. We expect a 20 percent annual dividend increase in both 2014 and 2015.

Overview of Three Months Ended March 31, 2014

Income (loss) from continuing operations attributable to The Williams Companies, Inc., for the three months ended March 31, 2014, changed unfavorably by $22 million compared to the three months ended March 31, 2013, primarily due to equity losses from the proposed Bluegrass Pipeline project, primarily reflecting a write-off of development costs that were previously capitalized and other associated costs that were incurred during the first quarter. The three months ended March 31, 2014 also reflects increased service revenues partially offset by lower NGL margins. See additional discussion in Results of Operations.

Abundant and low-cost natural gas reserves in the United States continue to drive strong demand for midstream and pipeline infrastructure. We believe that we have successfully positioned our energy infrastructure businesses for significant future growth.

Williams Partners

Canada Dropdown

On February 28, 2014, we contributed certain of our Canadian operations to WPZ, including an oil sands offgas processing plant near Fort McMurray, Alberta, an NGL/olefin fractionation facility and B/B splitter facility at Redwater, Alberta, and the Boreal pipeline. These businesses were previously reported within our Williams NGL & Petchem Services segment, but are now reported within Williams Partners. Prior period segment disclosures have been recast for this transaction. WPZ funded the transaction with $25 million of cash (subject to certain closing adjustments), the issuance of 25,577,521 Class D limited-partner units, and an increase in the capital account of its general partner to allow us to maintain our 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units. All Class D units outstanding will be convertible to common units beginning in the first quarter of 2016. The contribution agreement governing the Canada Dropdown provides that WPZ can issue additional Class D units to us on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions.

Opal Incident

On April 23, 2014, an explosion and fire occurred at our natural gas processing facility near Opal, Wyoming. There were no reported injuries or damage to property outside the facility. The facility was immediately shut down and natural gas gathering from surrounding producing areas was temporarily suspended as a result of the incident. The facility is primarily comprised of five turbo-expander (TXP) cryogenic gas-processing units. Although we have not yet made a full assessment of all plant equipment, the initial visual assessment of damage indicates that the impact was largely limited to the TXP-3 unit. We are inspecting the damaged equipment in cooperation with regulatory authorities and developing preliminary plans to bring the other four units back into service. The capacity of the four undamaged plants is sufficient to handle all of the natural gas currently available to the facility.

29

Management’s Discussion and Analysis (Continued)

We have insurance coverage, subject to retentions (deductibles), for property damage and business interruption that we expect to significantly mitigate the financial effects of the incident.

Geismar Incident

On June 13, 2013, an explosion and fire occurred at WPZ’s Geismar olefins plant. The fire was extinguished on the day of the incident. The Geismar Incident rendered the facility temporarily inoperable and resulted in significant human, financial, and operational effects.

We have substantial insurance coverage for repair and replacement costs, lost production and additional expenses related to the incident as follows:

• Property damage and business interruption coverage with a combined per-occurrence limit of $500 million and retentions (deductibles) of $10 million per occurrence for property damage and a 60-day waiting period per occurrence for business interruption;

• General liability coverage with per-occurrence and aggregate annual limits of $610 million and retentions (deductibles) of $2 million per occurrence;

• Workers’ compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence.

During the first quarter of 2014, we received $125 million of insurance recoveries related to the Geismar Incident and incurred $6 million of related covered insurable expenses in excess of our retentions (deductibles). These amounts are reflected as a net gain in Net insurance recoveries- Geismar Incident within Costs and expenses in our Consolidated Statement of Income.

Following the repair and an expansion of the plant, the Geismar plant is expected to begin start-up in the latter-half of June 2014. We expect our insurance coverage will significantly mitigate our financial loss. We currently estimate cash recoveries from insurers of approximately $430 million related to business interruption and approximately $70 million related to the repair of the plant. Of these amounts, we received $50 million of insurance proceeds during 2013 and $125 million in the first quarter of 2014. We are impacted by certain uninsured losses, including amounts associated with the 60-day waiting period for business interruption, as well as other deductibles, policy limits, and uninsured expenses. Our assumptions and estimates, including the timing for the expanded plant return to operation, repair cost estimates, and insurance proceeds associated with our property damage and business interruption coverage are subject to various risks and uncertainties that could cause the actual results to be materially different.

New Transco rates effective

On August 31, 2012, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceeding. The new rates became effective March 1, 2013, subject to refund and the outcome of a hearing. On August 27, 2013, Transco filed a stipulation and agreement with the FERC proposing to resolve all issues in this proceeding without the need for a hearing (Agreement). On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement became effective March 1, 2014. We accrued $118 million for rate refunds as of March 31, 2014, which were subsequently paid on April 18, 2014.

Caiman II

As a result of $119 million of contributions made in the first quarter of 2014, our ownership in the Caiman II joint project increased to 58 percent at March 31, 2014. These contributions are used to fund Caiman II’s 50 percent investment in Blue Racer Midstream LLC, which is expanding gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica Shale.

30

Management’s Discussion and Analysis (Continued)

Volatile commodity prices

NGL margins were approximately 26 percent lower in the first three months of 2014 compared to the same period of 2013 driven by lower volumes, as well as higher natural gas prices, partially offset by favorable non-ethane prices. Volumes declined primarily due to a customer contract in the West that expired in September 2013, as well as higher inventory levels. Due to unfavorable ethane economics, we continued our reduced recoveries of ethane in our domestic plants in the first quarter of 2014, consistent with the same period in 2013.

NGL margins are defined as NGL revenues less any applicable 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.

The following graph illustrates the effects of this price volatility, notably the decline in equity ethane sales driven by reduced recoveries, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.

Williams NGL & Petchem Services

Bluegrass Pipeline and Moss Lake

We own a 50 percent interest in the proposed Bluegrass Pipeline, which would connect processing facilities in the Marcellus and Utica shale-gas areas in the U.S. Northeast to growing petrochemical and export markets in the U.S. Gulf Coast. Completion of this project is subject to execution of customer contracts sufficient to support the project. Although discussions with potential customers continue, we have not received sufficient executed customer

31

Management’s Discussion and Analysis (Continued)

commitments to date to support the continued development of the project. Considering this and other factors, our management decided in April to discontinue further funding of the project at this time. Given these developments, the capitalized project development costs at the Bluegrass Pipeline entity were written off as of March 31, 2014, and as a result, we have recognized $67 million in related equity losses in the first quarter of 2014.

We also own 50 percent interests in Moss Lake Fractionation LLC and Moss Lake LPG Terminal LLC (collectively referred to as Moss Lake). Moss Lake may construct a proposed new large-scale fractionation plant, expand natural gas liquids storage facilities in Louisiana and construct a proposed pipeline connecting these facilities to the Bluegrass Pipeline. Additionally, Moss Lake may construct a proposed new liquefied petroleum gas (LPG) terminal. In the first quarter of 2014, we have recognized $4 million in equity losses related to Moss Lake, primarily associated with the underlying write off of capitalized project development costs at Moss Lake.

Company Outlook

Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas, natural gas products, and crude oil that exists in North America. We seek to accomplish this through further developing our scale positions in current key markets and basins and entering new growth markets and basins where we can become the large-scale service provider. We will maintain a strong commitment to safety, environmental stewardship, operational excellence and customer satisfaction. We believe that accomplishing these goals will position us to deliver an attractive return to our shareholders.

Fee-based businesses are a significant component of our portfolio. As we continue to transition to an overall business mix that is increasingly fee-based, the influence of commodity price fluctuations on our operating results and cash flows is expected to become somewhat less significant.

As previously noted, the financial impact of the Geismar Incident is expected to be significantly mitigated by our insurance policies. We expect the timing of recognizing recoveries under our business interruption policy will favorably impact our operating results in 2014.

Our business plan for 2014 reflects both significant capital investment and continued dividend growth. Our planned consolidated capital investments for 2014 total approximately $4.1 billion. We also expect approximately 20 percent growth in total 2014 dividends, which we expect to fund primarily with distributions received from WPZ and ACMP. We expect to maintain an attractive cost of capital and reliable access to capital markets, both of which will allow us to pursue development projects and acquisitions.

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

• General economic, financial markets, or industry downturn;

• Unexpected significant increases in capital expenditures or delays in capital project execution;

• Lower than anticipated or delay in receiving insurance recoveries associated with the Geismar Incident;

• Limited availability of capital due to a change in our financial condition, interest rates, market or industry conditions;

• 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;

• Counterparty credit and performance risk;

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

• Lower than anticipated energy commodity prices and margins;

32

Management’s Discussion and Analysis (Continued)

• Changes in the political and regulatory environments;

• Physical damages to facilities, including damage to offshore facilities by named windstorms;

• Reduced availability of insurance coverage.

We continue to address these risks through disciplined investment strategies, sufficient liquidity from cash and cash equivalents and available capacity under our revolving credit facilities.

In 2014, we anticipate an overall improvement in operating results compared to 2013 primarily due to an increase in our fee based, olefins, and Canadian midstream businesses, partially offset by lower NGL margins and higher operating expenses associated with the growth of our business.

The following factors, among others, could impact our businesses in 2014.

Williams Partners

Commodity price changes

NGL and olefin price changes have historically correlated somewhat with changes in the price of crude oil, although NGL, olefin, crude, and natural gas prices are highly volatile, and difficult to predict. Commodity margins are highly dependent upon regional supply/demand balances of natural gas as they relate to NGL margins, while olefins are impacted by continued demand within the global economy. NGL prices will benefit from exports to satisfy global demand. NGL products are currently the preferred feedstock for ethylene and propylene production, and are expected to remain advantaged over crude-based feedstocks into the foreseeable future. We continue to benefit from our strategic feedstock cost advantage in propylene production from Canadian oil sands offgas.

We anticipate the following trends in overall commodity prices in 2014 as compared to 2013:

• Natural gas prices are expected to be higher in part due to the additional demand to replace the gas volumes withdrawn during the colder than normal weather over the past winter season.

• Ethane prices are expected to be somewhat higher due to a modest increase in demand as well as slightly higher natural gas prices.  

• Propane prices are expected to be higher from an increase in exports and higher natural gas prices.

• Propylene prices are expected to be comparable to 2013 prices.

• Ethylene prices are expected to be slightly lower as compared to 2013 prices. The overall ethylene crack spread is also expected to be slightly lower due to the anticipated lower sales price and a projected higher ethane price. 

Gathering, processing, and NGL sales volumes

The growth of natural gas production supporting our gathering and processing volumes is impacted by producer drilling activities, which are influenced by commodity prices including natural gas, ethane and propane prices. In addition, the natural decline in production rates in producing areas impact the amount of gas available for gathering and processing. Due in part to the higher natural gas prices in the early part of 2014, we anticipate that overall drilling economics will improve slightly, which will benefit us in the long-term.

• In Williams Partners’ northeast region, we anticipate significant growth compared to the prior year in our natural gas gathering and processing volumes as our infrastructure grows to support drilling activities in the region.

33

Management’s Discussion and Analysis (Continued)

• In Williams Partners’ Transco and Northwest Pipeline businesses, we anticipate higher natural gas transportation revenues compared to 2013, as a result of expansion projects placed into service in 2013 and anticipated to be placed in service in 2014.

• In Williams Partners’ Gulf Coast region, we expect higher production handling volumes compared to 2013, following the scheduled completion of Gulfstar FPS™ in third quarter 2014.

• In Williams Partners’ western region, we anticipate an unfavorable impact in equity NGL volumes in 2014 compared to 2013, primarily due to a customer contract that expired in September 2013.

• In 2014, Williams Partners’ domestic businesses anticipate a continuation of periods when it will not be economical to recover ethane.

• In Williams Partners’ Canadian midstream business, we anticipate new ethane volumes in 2014 associated with the fourth quarter 2013 completion of the Canadian ethane recovery project, which is expected to benefit from a contractual minimum ethane sales price.

Olefin production volumes

• Williams Partners’ Gulf olefins business anticipates higher ethylene volumes in 2014 compared to 2013 substantially due to the repair and expansion of the Geismar plant expected to begin start-up in the latter-half of June 2014.

• Williams Partners’ Canadian olefins business expects higher propylene volumes in 2014 than 2013. Volumes in 2013 were negatively impacted by both a planned maintenance turnaround and downtime associated with the tie-in of the Canadian ethane recovery project.

Other

• Williams Partners’ Gulf olefins business received insurance recoveries of $50 million and $125 million in 2013 and the first quarter of 2014, respectively, related to the Geismar Incident and expects to receive additional insurance recoveries related to the Geismar Incident that will favorably impact our operating results in 2014.

• Williams Partners’ expects higher operating expenses in 2014 compared to 2013, including depreciation expense related to its growing operations in its northeast region and expansion projects in its gas pipeline and Gulf olefins businesses.

• Williams Partners’ expects higher equity earnings compared to 2013 following the scheduled completion of Discovery’s Keathley Canyon Connector™ lateral in the fourth quarter of 2014.

Access Midstream Partners

In the third-quarter of 2013, Access Midstream Partners increased its cash distribution by five cents per unit. Following the step-up in distributions in 2013, annual distributions to unitholders are expected to grow by approximately 15 percent in 2014 and 2015. We forecast that we will receive cash distributions of approximately $140 million from our investment in Access Midstream Partners for 2014.

Considering the expected distribution growth from Access Midstream Partners, including the benefit we receive from our 50 percent indirect interest in Access GP and its incentive distribution rights, we expect to recognize growing equity earnings from our investment. Our earnings recognized, however, will be reduced by the noncash amortization of the difference between the cost of our investment and our underlying share of the net assets of Access Midstream Partners.

34

Management’s Discussion and Analysis (Continued)

Expansion Projects

We expect to invest total capital in 2014 among our business segments as follows:

	Low		High
	(Millions)
Segment:
Williams Partners	$	3,000	$	3,500
Williams NGL & Petchem Services	400		500

Our ongoing major expansion projects include the following:

Williams Partners

Atlantic Sunrise

The Atlantic Sunrise Expansion Project involves an expansion of Transco’s existing natural gas transmission system along with greenfield facilities to provide firm transportation from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in Alabama.  We plan to file an application with the FERC in the second quarter of 2015 for approval of the project.  We plan to place the project into service during the second half of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 1,700 Mdth/d.

Leidy Southeast

In September 2013, we filed an application with the FERC for Transco’s Leidy Southeast Expansion project to expand our existing natural gas transmission system from the Marcellus Shale production region on Transco’s Leidy Line in Pennsylvania to delivery points along its mainline as far south as Station 85 in Alabama. We plan to place the project into service during the fourth quarter of 2015, assuming timely receipt of all necessary regulatory approvals, and expect it to increase capacity by 525 Mdth/d.

Mobile Bay South III

In April 2014, we received approval from the FERC to construct and operate an expansion of Transco’s Mobile Bay line south from Station 85 in west central Alabama to delivery points along the line. We plan to place the project into service during the second quarter of 2015 and it is expected to increase capacity on the line by 225 Mdth/d.

Constitution Pipeline

In June 2013, we filed an application with the FERC for authorization to construct and operate the jointly owned Constitution pipeline. We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will be the operator of Constitution. The 124-mile Constitution pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We plan to place the project into service in late 2015 to 2016, assuming timely receipt of all necessary regulatory approvals, with an expected capacity of 650 Mdth/d. The pipeline is fully subscribed with two shippers.

Northeast Connector

In April 2013, we filed an application with the FERC to expand Transco’s existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. We plan to place the project into service during the fourth quarter of 2014, assuming timely receipt of all necessary regulatory approvals, and expect it to increase capacity by 100 Mdth/d.

35

Management’s Discussion and Analysis (Continued)

Rockaway Delivery Lateral

In January 2013, we filed an application with the FERC for Transco to construct a three-mile offshore lateral to a distribution system in New York. We plan to place the project into service during the fourth quarter of 2014, assuming timely receipt of all necessary regulatory approvals, and the capacity of the lateral is expected to be 647 Mdth/d.

Virginia Southside

In November 2013, we received approval from the FERC to expand Transco’s existing natural gas transmission system from New Jersey to a proposed power station in Virginia and a delivery point in North Carolina. We plan to place the project into service during the third quarter of 2015, and expect it to increase capacity by 270 Mdth/d.

Marcellus Shale Expansions

• Expansion of our gathering infrastructure including compression and gathering pipelines in the Susquehanna Supply Hub in northeastern Pennsylvania as production in the Marcellus increases. The Susquehanna Supply Hub is expected to reach a natural gas take away capacity of 3 Bcf/d by 2015.

• In the first quarter of 2014, we completed a 30 Mbbls/d expansion of the Moundsville fractionator in the Marcellus Shale. In addition, we have several significant projects under construction with targeted construction completion in the first half of 2014. We are completing an installation of 40 Mbbls/d of deethanization capacity, a 50-mile ethane pipeline, condensate stabilization, and the first 200 MMcf/d of processing at Oak Grove.

• Expansions to the Laurel Mountain gathering system infrastructure to increase the capacity to 667 MMcf/d by the end of 2015 through capital contributions to this equity investment.

• Construction of the Blue Racer Midstream joint project, an expansion to gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and Northwest Pennsylvania through capital to be invested within our Caiman II equity investment. Expansion plans included the addition of Natrium II, a second 200 MMcf/d processing plant at Natrium, which was completed in April 2014. Construction of an additional 200 MMcf/d processing plant is underway at the Berne complex in Monroe County, Ohio. Berne I is expected to come online in the fourth quarter of 2014.

Gulfstar One

We designed, constructed, and are installing 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. Installation is under way and the project is expected to be in service in the third quarter 2014. In December 2013, Gulfstar One agreed to host the Gunflint development, which will result in an expansion of the Gulfstar One system to provide production handling capacity of 20 Mbbls/d and 40 MMcf/d for Gunflint. The Gunflint project is expected to be completed in the first quarter of 2016, dependent on the producer’s development activities.

Parachute

Due to a reduction in drilling in the Piceance basin during 2012 and early 2013, we delayed the in-service date of our 350 MMcf/d cryogenic natural gas processing plant in Parachute that was planned for service in 2014. We are currently planning an in-service date in mid-2016. We will continue to monitor the situation to determine whether a different in-service date is warranted.

36

Management’s Discussion and Analysis (Continued)

Geismar

As a result of the Geismar Incident, the expansion of our Geismar olefins production facility is expected to be completed when the Geismar plant returns to operation. We expect the plant to begin start-up in the latter-half of June 2014. The expansion 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. The additional capacity will be wholly owned by us and is expected to increase our ownership of the Geismar production facility from the current 83.3 percent.

Keathley Canyon Connector™

Discovery is constructing a 215-mile, 20-inch deepwater lateral pipeline in the central deepwater Gulf of Mexico that it will own and operate. Discovery has signed long-term agreements with anchor customers for natural gas gathering and processing services for production from the Keathley Canyon and Green Canyon areas. 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 gas will be processed at Discovery’s Larose Plant and the NGLs will be fractionated at Discovery’s Paradis Fractionator. 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. The pipeline is expected to be in service in the fourth quarter of 2014.

Redwater Expansion

As part of a long-term agreement to provide gas processing to a second bitumen upgrader in Canada’s oil sands near Fort McMurray, Alberta, we plan to increase the capacity of the Redwater facilities where NGL/olefins mixtures will be fractionated into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate. This project is expected to be placed into service during the third quarter of 2015.

Williams NGL & Petchem Services

Canadian PDH Facility

We are planning to build a PDH facility in Alberta that will significantly increase production of polymer-grade propylene. Start-up for the PDH facility is expected to occur in the second quarter of 2017. The new PDH facility is expected to produce approximately 1.1 billion pounds annually, significantly increasing Williams’ production of polymer-grade propylene currently at 180 million pounds annually.

NGL Infrastructure Expansion

As part of a long-term agreement to provide gas processing to a second bitumen upgrader in Canada’s oil sands near Fort McMurray, Alberta, we plan to build a new liquids extraction plant and an extension of the Boreal Pipeline. The extension of the Boreal Pipeline will enable transportation of the NGL/olefins mixture from the new extraction plant. The NGL/olefins recovered are initially expected to be approximately 12 Mbbls/d by mid-2015. To mitigate the associated ethane price risk, we have a long-term supply agreement with a third-party customer.

Gulf Coast Expansion

In November 2012, we acquired 10 liquids 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 include the construction and commissioning of pipeline systems capable of transporting various products in the Gulf Coast region. The projects are expected to be placed into service beginning in late 2014 through 2015.

37

Management’s Discussion and Analysis (Continued)

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2014, compared to the three months ended March 31, 2013. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

	Three months ended    March 31,
	2014			2013			$ Change*	% Change*
	(Millions)
Revenues:
Service revenues	$	819		$	706		+113	+16%
Product sales	930			1,104			-174	-16%
Total revenues	1,749			1,810
Costs and expenses:
Product costs	769			790			+21	+3%
Operating and maintenance expenses	298			260			-38	-15%
Depreciation and amortization expenses	214			201			-13	-6%
Selling, general, and administrative expenses	150			132			-18	-14%
Net insurance recoveries – Geismar Incident	(119		)	—			+119	NM
Other (income) expense – net	17			1			-16	NM
Total costs and expenses	1,329			1,384
Operating income (loss)	420			426
Equity earnings (losses)	(48		)	18			-66	NM
Interest expense	(140		)	(128		)	-12	-9%
Other investing income – net	14			13			+1	+8%
Other income (expense) – net	1			(2		)	+3	NM
Income (loss) from continuing operations before income taxes	247			327
Provision (benefit) for income taxes	51			96			+45	+47%
Income (loss) from continuing operations	196			231
Income (loss) from discontinued operations	—			(1		)	+1	NM
Net income (loss)	196			230
Less: Net income attributable to noncontrolling interests	56			69			+13	+19%
Net income (loss) attributable to The Williams Companies, Inc.	$	140		$	161

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

Three months ended March 31, 2014 vs. three months ended March 31, 2013

Service revenues in our Williams Partners segment increased due primarily to an increase in natural gas transportation fee revenues related to projects placed in service in 2013 and new rates effective in March 2013 for Transco, as well as higher fees associated with higher gathering volumes driven by new well connections and increased gathering rates in our businesses in the Northeast area. Service revenues at Other also increased related to new Canadian construction management services performed for third parties.

38

Management’s Discussion and Analysis (Continued)

Product sales decreased primarily due to lower olefin sales related to the lack of production as a result of the Geismar Incident and a decrease in volumes at our RGP splitter primarily due to an outage in a third-party storage facility which caused us to reduce production. NGL production revenues also decreased reflecting lower non-ethane sales volumes partially offset by higher non-ethane per-unit sales prices and higher ethane sales volumes in Canada. Marketing sales revenues increased primarily due to higher NGL per-unit sales prices and higher ethane volumes, partially offset by lower volumes of non-ethane NGLs and other products. The changes in marketing revenues are substantially offset by similar changes in marketing purchases, reflected above as Product costs.

Product costs decreased primarily due to lower olefin feedstock purchases related to the lack of production as a result of the Geismar Incident and a decrease in volumes at our RGP splitter, as previously discussed, partially offset by an increase in marketing purchases. The changes in marketing purchases are more than offset by similar changes in marketing revenues.

Operating and maintenance expenses increased related to costs incurred associated with new Canadian construction management services performed for third parties.

Depreciation and amortization expenses increased primarily due to depreciation on infrastructure additions in the Northeast area and the Canadian ethane recovery project placed into service in fourth quarter 2013.

Selling, general, and administrative expenses increased primarily due to $19 million of project development costs incurred in 2014 related to the Bluegrass Pipeline reflecting 100 percent of such costs. The 50 percent noncontrolling interest share of these costs are presented in Net income attributable to noncontrolling interests.

The favorable change in Net insurance recoveries – Geismar Incident is due to receipt of $125 million of insurance recoveries partially offset by $6 million of related covered insurable expenses in excess of our retentions (deductibles) incurred in the first quarter of 2014. (See Note 3 – Other Income and Expenses of Notes to Consolidated Financial Statements.)

The unfavorable change in Other (income) expense – net within Operating income is primarily due to the absence of a $6 million favorable contingency settlement recognized in first-quarter 2013 and costs incurred in first quarter 2014 associated with fire damage at a compressor station in the Susquehanna Supply Hub.

Operating income decreased primarily due to a $122 million decrease in olefin margins, including $111 million lower product margins at our Geismar plant, and decreases in NGL margins driven primarily by lower NGL volumes, as well as higher depreciation and amortization expense in 2014. These decreases were substantially offset by $125 million of income associated with insurance recoveries related to the Geismar Incident and a $61 million increase in service revenues at Williams Partners.

Equity earnings (losses) changed unfavorably primarily due to $77 million of equity losses from Bluegrass Pipeline and Moss Lake related primarily to the underlying write-off of previously capitalized project development costs, (see Note 2 – Variable Interest Entities of Notes to Consolidated Financial Statements.) Higher equity earnings from Access Midstream Partners partially offset these losses.

Interest expense increased due to a $17 million increase in Interest incurred primarily due to new debt issuances in the fourth quarter of 2013 and first quarter of 2014 (see Note 8 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements).

Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income. See Note 4 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.

The favorable change in Net income attributable to noncontrolling interests primarily reflects our partner’s 50 percent share of project development costs expensed by Bluegrass Pipeline during the portion of the first quarter of 2014 that we consolidated Bluegrass Pipeline.

39

Management’s Discussion and Analysis (Continued)

Period-Over-Period Operating Results - Segments

Williams Partners

	Three months ended    March 31,
	2014			2013
	(Millions)
Segment revenues	$	1,693		$	1,806
Segment costs and expenses	(1,213		)	(1,330		)
Equity earnings (losses)	23			18
Segment profit	$	503		$	494

Three months ended March 31, 2014 vs. three months ended March 31, 2013

The decrease in segment revenues includes:

• A $190 million decrease in olefin sales primarily associated with a $161 million decrease in volumes due to the lack of production in 2014 as a result of the Geismar Incident and a $25 million decrease in volumes at our RGP splitter primarily due to an outage in a third-party storage facility which caused us to reduce production (substantially offset in Product costs).

• A $29 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $56 million due to lower volumes, partially offset by a $27 million increase associated with 16 percent higher average non-ethane per-unit sales prices. Equity non-ethane sales volumes are 31 percent lower primarily due to a customer contract that expired in September 2013 and higher inventory levels, partially offset by 44 percent higher equity ethane sales volumes primarily driven by new volumes from the Canadian ethane recovery project placed into service in the fourth quarter of 2013.

• A $61 million increase in service revenues primarily due to $31 million higher natural gas transportation revenues from expansion projects placed into service in 2013, as well as new rates effective in March 2013 for Transco. In addition, fee revenues increased $27 million resulting from higher gathering volumes driven by new well connections and increased gathering rates associated with customer contract modifications in the Northeast region primarily in the Susquehanna Supply Hub. Fee revenues also increased $9 million due to contributions from our Ohio Valley Midstream business resulting from the processing and fractionation facilities placed in service in 2013. These increases are partially offset by $10 million lower production handling, lower gathering, and lower crude oil transportation fee revenues in the Gulf Coast region due to a decrease in production area volumes and producers' operational issues.

• A $44 million increase in marketing revenues primarily associated with higher NGL prices and higher ethane volumes, partially offset by lower non-ethane volumes and other products. The changes in marketing revenues are substantially offset by similar changes in marketing purchases.

The decrease in segment costs and expenses includes:

• A $119 million favorable change in Net insurance recoveries – Geismar Incident attributable to the receipt of $125 million of insurance recoveries during the first quarter of 2014, partially offset by $6 million of related covered insurable expenses in excess of our retentions (deductibles).

• A $68 million decrease in olefin feedstock purchases primarily associated with a $49 million decrease in volumes due to the lack of production in 2014 as a result of the Geismar Incident and a $23 million decrease in volumes at our RGP splitter primarily due to the third-party storage facility outage, as discussed above (more than offset in Product sales).

40

Management’s Discussion and Analysis (Continued)

• A $37 million increase in marketing purchases primarily due to higher NGL prices and higher ethane volumes, partially offset by lower non-ethane volumes and other products (more than offset in marketing revenues).

• A $9 million increase in costs associated with the production of our equity NGLs reflecting a $30 million increase related to higher average natural gas prices, partially offset by a decrease of $21 million associated with lower volumes.

• An $8 million increase in operating costs primarily due to a $12 million increase in Depreciation and amortization expenses associated with the Ohio Valley Midstream and Susquehanna Supply Hub businesses due to growth in these operations and the ethane recovery project placed into service in fourth-quarter 2013 associated with our Canadian operations.

• A $16 million unfavorable change in Other (income) expense – net primarily due to the absence of a $6 million favorable contingency settlement recognized in first-quarter 2013 and costs incurred in first-quarter 2014 associated with fire damage at a compressor station in the Susquehanna Supply Hub.

The increase in segment profit includes:

• A $119 million favorable change in Net insurance recoveries – Geismar Incident as previously discussed.

• A $61 million increase in service revenues as previously discussed.

• A $7 million increase in marketing margins.

• A $122 million decrease in olefin margins, including $111 million lower olefin margins at our Geismar plant and $10 million lower olefin margins associated with our Canadian operations driven by lower volumes and higher natural gas prices.

• A $38 million decrease in NGL margins driven primarily by lower NGL volumes and higher natural gas prices, partially offset by higher average NGL prices and lower natural gas volumes.

• A $16 million unfavorable change in Other (income) expense – netas previously discussed.

• An $8 million increase in operating costs as previously discussed.

Williams NGL & Petchem Services

	Three months ended    March 31,
	2014			2013
	(Millions)
Segment costs and expenses	$	(23	)	$	(2	)
Equity earnings (losses)	(77		)	—
Segment profit (loss)	$	(100	)	$	(2	)

Three months ended March 31, 2014 vs. three months ended March 31, 2013

Segment costs and expenses increased $21 million primarily due to $19 million of project development costs expensed during the first quarter of 2014 related to the Bluegrass Pipeline.

The unfavorable change in Equity earnings (losses) is due to equity losses from Bluegrass Pipeline and Moss Lake related primarily to the underlying write-off of previously capitalized project development costs.

The unfavorable change in Segment profit (loss) is due to equity losses from Bluegrass Pipeline and Moss Lake as well as costs incurred during the first quarter of 2014 related to the development of the Bluegrass Pipeline.

41

Management’s Discussion and Analysis (Continued)

Access Midstream Partners

	Three months ended    March 31,
	2014		2013
	(Millions)
Segment profit	$	6	$	—

Three months ended March 31, 2014 vs. three months ended March 31, 2013

Segment profit includes equity earnings recognized from ACMP of $21 million and $17 million in 2014 and 2013, respectively. Offsetting the equity earnings are charges of $15 million and $17 million in 2014 and 2013, respectively, of noncash amortization of the difference between the cost of our investment and our underlying share of the net assets of ACMP.

We received regular quarterly distributions from ACMP of $31 million and $20 million during the first quarter of 2014 and 2013, respectively.

Other

	Three months ended    March 31,
	2014		2013
	(Millions)
Segment revenues	$	59	$	7
Segment profit (loss)	3		(5		)

Three months ended March 31, 2014 vs. three months ended March 31, 2013

Segment revenues increased due to new Canadian construction management services performed for third parties (substantially offset in segment costs and expenses).

Segment costs and expenses increased by $44 million primarily due to new Canadian construction management services performed for third parties.

The favorable change in segment profit (loss) reflects the absence of $6 million of project development costs incurred during the first quarter of 2013.

42

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

We seek to manage our businesses with a focus on applying conservative financial policy in order to maintain investment-grade credit metrics. Our plan for 2014 reflects our ongoing transition to an overall business mix that is increasingly fee-based. Although our cash flows are impacted by fluctuations in energy commodity prices, that impact is somewhat mitigated by certain of our cash flow streams that are not directly impacted by short-term commodity price movements, including:

• Firm demand and capacity reservation transportation revenues under long-term contracts;

• Fee-based revenues from certain gathering and processing services.

We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, dividends and distributions, debt service payments, and tax payments, including a $90 million tax payment as a result of WPZ’s acquisition of certain of our Canadian operations, while maintaining a sufficient level of liquidity. In particular, we note the following:

• We expect capital and investment expenditures to total between $3.76 billion and $4.44 billion in 2014. 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 $360 million and $440 million. Expansion capital expenditures, which are generally more discretionary as compared to maintenance capital expenditures, are used to fund projects in order to grow our business and are expected to total between $3.4 billion and $4 billion. See Company Outlook – Expansion Projects for discussions describing the general nature of these expenditures. 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 $1.75 per common share in 2014, an increase of 22 percent over 2013 levels.

• We expect to fund working capital requirements, capital and investment expenditures, debt service payments, dividends and distributions and tax payments primarily through cash flow from operations, cash and cash equivalents on hand, issuances of WPZ debt and/or equity securities, and utilization of our credit facility and WPZ’s credit facility and/or commercial paper program.

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 2014. Our internal and external sources of consolidated liquidity include:

• Cash generated from our operations, including cash distributions from WPZ and our equity-method investments based on our level of ownership and incentive distribution rights;

• Cash and cash equivalents on hand;

• Cash proceeds from WPZ’s issuances of debt and/or equity securities;

• Use of WPZ’s commercial paper program and/or credit facility.

Additional sources of liquidity available to us at the parent level include our credit facility, proceeds from the issuance of debt and/or equity securities, and proceeds from asset sales. WPZ is expected to be self-funding through its cash flows from operations, use of its commercial paper program and/or credit facility, and its access to capital markets.

43

Management’s Discussion and Analysis (Continued)

Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include those previously discussed in Company Outlook.

As of March 31, 2014, we had a working capital deficit (current liabilities, in excess of current assets) of $371 million. However, we note the following about our available liquidity.

	March 31, 2014
Available Liquidity	WPZ		WMB		Total
	(Millions)
Cash and cash equivalents	$	535	$	529	$	1,064
Capacity available under our $1.5 billion credit facility (expires July 31, 2018) (1)			1,500		1,500
Capacity available to WPZ under its $2.5 billion five-year credit facility (expires July 31, 2018) less amounts outstanding under its $2 billion commercial paper program (2)	2,500				2,500
	$	3,035	$	2,029	$	5,064

(1) We have not borrowed on our credit facility during 2014. At March 31, 2014, we are in compliance with the financial covenants associated with this credit facility. The credit facility capacity, under certain circumstances, may be increased up to an additional $500 million.

(2) WPZ has not borrowed on its credit facility during 2014 and has no Commercial paper outstanding at March 31, 2014. The highest amount outstanding under the commercial paper program during 2014 was $900 million. At March 31, 2014, WPZ is in compliance with the financial covenants associated with the credit facility and commercial paper program. The WPZ credit facility is only available to WPZ, Transco, and Northwest Pipeline as co-borrowers and under certain circumstances, the capacity may be increased up to an additional $500 million. In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of WPZ’s credit facility inclusive of any outstanding amounts under WPZ’s commercial paper program.

In addition to the credit facilities and WPZ’s commercial paper program listed above, we have issued letters of credit totaling $15 million and WPZ has issued letters of credit totaling $9 million as of March 31, 2014, under certain bilateral bank agreements.

Debt Offering

On March 4, 2014, WPZ completed a public offering of $1 billion of 4.3 percent senior unsecured notes due 2024 and $500 million of 5.4 percent senior unsecured notes due 2044. WPZ used a portion of the net proceeds to repay amounts outstanding under its commercial paper program and expects to utilize the remainder to fund capital expenditures and for general partnership purposes.

Distributions from Equity-Method Investees

Our equity-method investees’ organizational documents require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.

Shelf Registration

In April 2013, WPZ filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in WPZ having an aggregate offering price of up to $600 million. These sales will be made over a period of time and from time to time in transactions at prices which are market prices prevailing at the time of sale, prices related to market price or at negotiated prices. Such sales will be made pursuant to an equity distribution agreement between WPZ and certain banks who may act as sales agents or purchase for its own accounts as principals. As of March 31, 2014, no common units have been issued under this registration.

44

Management’s Discussion and Analysis (Continued)

WPZ Incentive Distribution Rights

Our ownership interest in WPZ includes the right to incentive distributions determined in accordance with WPZ’s partnership agreement. In connection with the contribution of certain Gulf olefins assets to WPZ in November 2012, we agreed to waive $16 million per quarter of incentive distributions until the later of December 31, 2013 or 30 days after the Geismar plant expansion is operational.

Insurance Renewal

Our onshore property damage and business interruption insurance coverage renewed on May 1st, with a combined per-occurrence limit between $500 million and $750 million, subject to retentions (deductibles) of $40 million per occurrence for property damage and a waiting period of 120 days per occurrence for business interruption.

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	Outlook	Senior Unsecured Debt Rating	Corporate Credit Rating
Williams:
	Standard & Poor’s	Stable	BBB-	BBB
	Moody’s Investors Service	Stable	Baa3	N/A
	Fitch Ratings	Stable	BBB-	N/A
Williams Partners:
	Standard & Poor’s	Stable	BBB	BBB
	Moody’s Investors Service	Stable	Baa2	N/A
	Fitch Ratings	Stable	BBB	N/A

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

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

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 its 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 March 31, 2014, we estimate that a downgrade to a rating below investment grade for us or WPZ could require us to post up to $1 million or $281 million, respectively, in additional collateral with third parties.

45

Management’s Discussion and Analysis (Continued)

Sources (Uses) of Cash

	Three months ended    March 31,
	2014			2013
	(Millions)
Net cash provided (used) by:
Operating activities	$	446		$	495
Financing activities	929			176
Investing activities	(992		)	(808		)
Increase (decrease) in cash and cash equivalents	$	383		$	(137	)

Operating activities

The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash expenses such as Depreciation and amortizationandProvision (benefit) for deferred income taxes. Our Net cash provided by operating activities was also impacted by net favorable changes in operating working capital.

Financing activities

Significant transactions include:

• $225 million net payments in 2014 on WPZ’s commercial paper;

• $1.496 billion net received in 2014 from WPZ’s previously mentioned debt offering;

• $770 million received in 2013 from WPZ’s credit facility borrowings;

• $895 million paid in 2013 on WPZ’s credit facility borrowings;

• $617 million received in 2013 from WPZ’s equity offerings;

• $276 million in 2014 and $231 million in 2013 paid for quarterly dividends on common stock;

• $147 million in 2014 and $105 million in 2013 paid for dividends and distributions to noncontrolling interests;

• $63 million received in 2014 from contributions from noncontrolling interests.

Investing activities

Significant transactions include:

• Capital expenditures of $793 million in 2014 and $713 million in 2013;

• Purchases of and contributions to our equity-method investments of $228 million in 2014 and $93 million in 2013.

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

We have various other guarantees and commitments which are disclosed in Note 2 – Variable Interest Entities, Note 10 – Fair Value Measurements and Guarantees, and Note 11 – Contingent Liabilities 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.

46

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 three months of 2014.

Foreign Currency Risk

Our foreign operations, whose functional currency is the local currency, are located primarily in Canada. Net assets of our foreign operations were approximately $1.14 billion and $1.12 billion at March 31, 2014 and December 31, 2013, respectively. These investments have the potential to impact our financial position due to fluctuations in these local currencies arising from the process of translating the local functional currency into the U.S. dollar. As an example, a 20 percent change in the respective functional currencies against the U.S. dollar would have changed total stockholders’ equity by approximately $117 million at March 31, 2014.

47

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 also is 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.

Changes in Internal Controls Over Financial Reporting

There have been no changes during the first quarter of 2014 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting.

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. Since 2011 we have not received any additional requests for information related to these facilities.

48

In November 2013 we became aware of deficiencies with the air permit for the Ft. Beeler gas processing facility located in West Virginia.  We notified the EPA and the West Virginia Department of Environmental Protection and are working to bring the Ft. Beeler facility into full compliance.  At March 31, 2014, we have accrued liabilities of $100,000 for potential penalties arising out of the deficiencies.

Other

The additional information called for by this item is provided in Note 11 – Contingent Liabilities 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.

49

Item 6. Exhibits

Exhibit No.		Description
Exhibit 3.1	—	Amended and Restated Certificate of Incorporation (filed on May 26, 2010, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
Exhibit 3.2	—	By-Laws (filed on May 26, 2010, as Exhibit 3.2 to The Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
Exhibit 10.1	—	Settlement Agreement, dated as of February 25, 2014, by and among Corvex Management LP, Keith Meister, Soroban Master Fund LP, Soroban Capital Partners LLC, Eric W. Mandelblatt, and The Williams Companies, Inc. (filed on February 25, 2014, as Exhibit 99.1 to The Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
*Exhibit 10.2§	—	Letter Agreement, dated January 27, 2014, with James E. Scheel, Senior Vice President - Northeast G&P, regarding Relocation from Pennsylvania Benefits.
*Exhibit 12	—	Computation of Ratio of Earnings to Fixed Charges.
*Exhibit 31.1	—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*Exhibit 31.2	—	Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**Exhibit 32	—	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*Exhibit 101.INS	—	XBRL Instance Document.
*Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema.
*Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase.
*Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase.
*Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase.
*Exhibit 101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase.

*    Filed herewith.

**    Furnished herewith.

§    Management contract or compensatory plan or arrangement.

50

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)

May 1, 2014

EXHIBIT INDEX

Exhibit No.		Description
Exhibit 3.1	—	Amended and Restated Certificate of Incorporation (filed on May 26, 2010, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
Exhibit 3.2	—	By-Laws (filed on May 26, 2010, as Exhibit 3.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
Exhibit 10.1	—	Settlement Agreement, dated as of February 25, 2014, by and among Corvex Management LP, Keith Meister, Soroban Master Fund LP, Soroban Capital Partners LLC, Eric W. Mandelblatt, and The Williams Companies, Inc. (filed on February 25, 2014, as Exhibit 99.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference.)
*Exhibit 10.2§	—	Letter Agreement, dated January 27, 2014, with James E. Scheel, Senior Vice President - Northeast G&P, regarding Relocation from Pennsylvania Benefits.
*Exhibit 12	—	Computation of Ratio of Earnings to Fixed Charges.
*Exhibit 31.1	—	Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*Exhibit 31.2	—	Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**Exhibit 32	—	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*Exhibit 101.INS	—	XBRL Instance Document.
*Exhibit 101.SCH	—	XBRL Taxonomy Extension Schema.
*Exhibit 101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase.
*Exhibit 101.DEF	—	XBRL Taxonomy Extension Definition Linkbase.
*Exhibit 101.LAB	—	XBRL Taxonomy Extension Label Linkbase.
*Exhibit 101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase.

*    Filed herewith.

**    Furnished herewith.

§    Management contract or compensatory plan or arrangement.