Edgar Filing: WILLIAMS COMPANIES INC

Large accelerated filer þ

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller reporting company)

WMB_2013.09.30_10Q

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 September 30, 2013



¨	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. Yes þ No ¨

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes ¨ No þ

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



Class		Outstanding at October 28, 2013
Common Stock, $1 par value		683,428,418 Shares

The Williams Companies, Inc.

Index



	Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Income – Three and Nine Months Ended September 30, 2013 and 2012	4
Consolidated Statement of Comprehensive Income – Three and Nine Months Ended September 30, 2013 and 2012	5
Consolidated Balance Sheet – September 30, 2013 and December 31, 2012	6
Consolidated Statement of Changes in Equity – Nine Months Ended September 30, 2013	7
Consolidated Statement of Cash Flows – Nine Months Ended September 30, 2013 and 2012	8
Notes to Consolidated Financial Statements	9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3. Quantitative and Qualitative Disclosures About Market Risk	55
Item 4. Controls and Procedures	56
Part II. Other Information	56
Item 1. Legal Proceedings	56
Item 1A. Risk Factors	57
Item 6. Exhibits	58

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;


•	Seasonality of certain business components;


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


•	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, 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;


•	Ability to acquire new businesses and assets and 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 strategy and 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.

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, 2012, and Part II, Item 1A. Risk Factors of this Form 10-Q.

PART I – FINANCIAL INFORMATION

The Williams Companies, Inc.

Consolidated Statement of Income

(Unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
	(Millions, except per-share amounts)
Revenues:
Service revenues	$	736		$	675		$	2,163		$	2,019
Product sales	887			1,077			3,037			3,598
Total revenues	1,623			1,752			5,200			5,617
Costs and expenses:
Product costs	710			771			2,301			2,628
Operating and maintenance expenses	269			261			820			766
Depreciation and amortization expenses	207			196			606			545
Selling, general, and administrative expenses	130			137			385			415
Other (income) expense – net	(29		)	14			(24		)	31
Total costs and expenses	1,287			1,379			4,088			4,385
Operating income (loss)	336			373			1,112			1,232
Equity earnings (losses)	37			30			93			88
Interest incurred	(151		)	(140		)	(454		)	(421		)
Interest capitalized	27			11			75			33
Other investing income – net	10			3			62			75
Other income (expense) – net	1			—			1			(1		)
Income (loss) from continuing operations before income taxes	260			277			889			1,006
Provision (benefit) for income taxes	62			77			260			281
Income (loss) from continuing operations	198			200			629			725
Income (loss) from discontinued operations	(1		)	3			(10		)	138
Net income (loss)	197			203			619			863
Less: Net income attributable to noncontrolling interests	56			48			175			153
Net income (loss) attributable to The Williams Companies, Inc.	$	141		$	155		$	444		$	710
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations	$	143		$	152		$	454		$	572
Income (loss) from discontinued operations	(2		)	3			(10		)	138
Net income (loss)	$	141		$	155		$	444		$	710
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	.21		$	.25		$	.66		$	.94
Income (loss) from discontinued operations	—			—			(.01		)	.22
Net income (loss)	$	.21		$	.25		$	.65		$	1.16
Weighted-average shares (thousands)	683,274			626,809			682,744			613,888
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	.20		$	.25		$	.66		$	.93
Income (loss) from discontinued operations	—			—			(.01		)	.22
Net income (loss)	$	.20		$	.25		$	.65		$	1.15
Weighted-average shares (thousands)	687,306			632,019			687,007			619,765
Cash dividends declared per common share	$	.36625		$	.3125		$	1.0575		$	.87125

See accompanying notes.

The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income

(Unaudited)



	Three months ended September 30,						Nine months ended September 30,
(Millions)	2013			2012			2013			2012
Net income (loss)	$	197		$	203		$	619		$	863
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $3 and ($9) in 2012	1			(9		)	1			25
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $3 and $5 in 2012	(1		)	(11		)	(1		)	(15		)
Foreign currency translation adjustments	20			30			(31		)	32
Pension and other postretirement benefits:
Prior service credit arising during the year, net of taxes of ($8) and ($8) in 2013 (Note 7)	15			—			15			—
Amortization of prior service cost (credit) included in net periodic benefit cost, net of taxes of $1 and $1 in 2013	—			—			(1		)	(1		)
Net actuarial gain (loss) arising during the year, net of taxes of ($7) and ($7) in 2013 and $1 and $2 in 2012 (Note 7)	12			(1		)	12			(4		)
Amortization of actuarial (gain) loss included in net periodic benefit cost, net of taxes of ($7) and ($18) in 2013 and ($6) and ($17) in 2012	9			10			29			29
Reclassifications into earnings of (gain) loss on sale of equity securities, net of taxes of $2 in 2012	—			—			—			(3		)
Other comprehensive income (loss)	56			19			24			63
Comprehensive income (loss)	253			222			643			926
Less: Comprehensive income (loss) attributable to noncontrolling interests	56			40			175			157
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	197		$	182		$	468		$	769

See accompanying notes.

The Williams Companies, Inc.

Consolidated Balance Sheet

(Unaudited)



(Millions, except per-share amounts)	September 30, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	732		$	839
Accounts and notes receivable	590			688
Deferred income tax asset	117			117
Inventories	230			175
Regulatory assets	32			39
Other current assets and deferred charges	81			66
Total current assets	1,782			1,924
Investments	4,278			3,987
Property, plant and equipment, at cost	24,934			22,546
Accumulated depreciation and amortization	(7,467		)	(7,079		)
Property, plant and equipment – net	17,467			15,467
Goodwill	646			649
Other intangibles	1,659			1,704
Regulatory assets, deferred charges, and other	623			596
Total assets	$	26,455		$	24,327
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,014		$	920
Accrued liabilities	700			628
Commercial paper	371			—
Long-term debt due within one year	1			1
Total current liabilities	2,086			1,549
Long-term debt	10,359			10,735
Deferred income taxes	3,414			2,841
Other noncurrent liabilities	1,650			1,775
Contingent liabilities (Note 12)
Equity:
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 718 million shares issued at September 30, 2013 and 716 million shares issued at December 31, 2012)	718			716
Capital in excess of par value	11,582			11,134
Retained deficit	(5,973		)	(5,695		)
Accumulated other comprehensive income (loss)	(338		)	(362		)
Treasury stock, at cost (35 million shares of common stock)	(1,041		)	(1,041		)
Total stockholders’ equity	4,948			4,752
Noncontrolling interests in consolidated subsidiaries	3,998			2,675
Total equity	8,946			7,427
Total liabilities and equity	$	26,455		$	24,327

See accompanying notes.

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity

(Unaudited)



	The Williams Companies, Inc., Stockholders
	Common Stock		Capital in Excess of Par Value		Retained Deficit			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Stockholders’ Equity			Noncontrolling Interest			Total
	(Millions)
Balance – December 31, 2012	$	716	$	11,134	$	(5,695	)	$	(362	)	$	(1,041	)	$	4,752		$	2,675		$	7,427
Net income (loss)	—		—		444			—			—			444			175			619
Other comprehensive income (loss)	—		—		—			24			—			24			—			24
Cash dividends – common stock	—		—		(722		)	—			—			(722		)	—			(722		)
Dividends and distributions to noncontrolling interests	—		—		—			—			—			—			(344		)	(344		)
Issuance of common stock from debentures conversion	—		1		—			—			—			1			—			1
Stock-based compensation and related common stock issuances, net of tax	2		38		—			—			—			40			—			40
Sales of limited partner units of Williams Partners L.P.	—		—		—			—			—			—			1,819			1,819
Changes in ownership of consolidated subsidiaries, net	—		409		—			—			—			409			(652		)	(243		)
Contributions from noncontrolling interests	—		—		—			—			—			—			327			327
Other	—		—		—			—			—			—			(2		)	(2		)
Balance – September 30, 2013	$	718	$	11,582	$	(5,973	)	$	(338	)	$	(1,041	)	$	4,948		$	3,998		$	8,946

See accompanying notes.

The Williams Companies, Inc.

Consolidated Statement of Cash Flows

(Unaudited)



	Nine months ended September 30,
(Millions)	2013			2012
OPERATING ACTIVITIES:
Net income (loss)	$	619		$	863
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	606			545
Provision (benefit) for deferred income taxes	301			117
Net (gain) loss on dispositions of assets	1			(56		)
Gain on reconsolidation of Wilpro entities (Note 3)	—			(144		)
Amortization of stock-based awards	28			27
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	85			82
Inventories	(53		)	19
Other current assets and deferred charges	11			28
Accounts payable	(47		)	(165		)
Accrued liabilities	91			14
Other, including changes in noncurrent assets and liabilities	60			(41		)
Net cash provided (used) by operating activities	1,702			1,289
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	370			—
Proceeds from long-term debt	1,705			2,109
Payments of long-term debt	(2,081		)	(1,313		)
Proceeds from issuance of common stock	14			935
Proceeds from sale of limited partner units of consolidated partnership	1,819			1,559
Dividends paid	(722		)	(538		)
Dividends and distributions paid to noncontrolling interests	(344		)	(246		)
Distributions paid to noncontrolling interests on sale of Wilpro assets (Note 3)	—			(38		)
Contributions from noncontrolling interests	327			4
Other – net	6			26
Net cash provided (used) by financing activities	1,094			2,498
INVESTING ACTIVITIES:
Capital expenditures*	(2,542		)	(1,652		)
Purchases of and contributions to equity method investments	(350		)	(282		)
Purchases of businesses	—			(2,049		)
Proceeds from dispositions of investments	—			79
Cash of Wilpro entities upon reconsolidation (Note 3)	—			121
Other – net	(11		)	103
Net cash provided (used) by investing activities	(2,903		)	(3,680		)
Increase (decrease) in cash and cash equivalents	(107		)	107
Cash and cash equivalents at beginning of period	839			889
Cash and cash equivalents at end of period	$	732		$	996
_________
* Increases to property, plant, and equipment	$	(2,685	)	$	(1,784	)
Changes in related accounts payable and accrued liabilities	143			132
Capital expenditures	$	(2,542	)	$	(1,652	)

See accompanying notes.

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, 2012, 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 domestic 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 consolidated interest in Constitution Pipeline Company, LLC (Constitution). 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, and a refinery grade splitter in Louisiana.

Williams NGL & Petchem Services consists primarily of a Canadian oil sands offgas processing plant located near Fort McMurray, Alberta, an NGL/olefin fractionation facility and butylene/butane splitter facility at Redwater, Alberta, and a 50 percent consolidated interest in Bluegrass Pipeline Company LLC (Bluegrass Pipeline).

Access Midstream Partners consists of our equity investment in Access Midstream Partners, L.P. (ACMP). As of September 30, 2013, 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.

Basis of Presentation

As disclosed in our 2012 Annual Report on Form 10-K, we contributed our 83.3 percent undivided interest in the olefins-production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf region to WPZ in November 2012. As a result, prior period segment disclosures have been recast for this transaction.

Notes (Continued)

Also as disclosed in our 2012 Annual Report on Form 10-K, we have revised the overall presentation of our Consolidated Statement of Income, including the separate presentation of service revenues, product sales, product costs, and depreciation and amortization expenses. All prior periods presented have been recast, along with corresponding information presented in the Notes to Consolidated Financial Statements, to reflect this change.

Consolidated master limited partnership

During the first quarter of 2013, WPZ completed equity issuances of 15,937,500 common units representing limited partner interests, including 3,000,000 common units sold to us in a private placement transaction. In the third quarter of 2013, WPZ completed equity issuances of 24,725,000 common units representing limited partner interests. Following these transactions, we own approximately 64 percent of the interests in WPZ, including the interests of the general partner, which are wholly owned by us, and incentive distribution rights as of September 30, 2013.

The previously described equity issuances by WPZ had the combined net impact of increasing our noncontrolling interests in consolidated subsidiaries by $1.169 billion, capital in excess of par value by $408 million and deferred income taxes by $242 million in the Consolidated Balance Sheet.

WPZ is self-funding and maintains separate lines of bank credit and cash management accounts. WPZ also initiated its commercial paper program in the first quarter of 2013. (See Note 9 – 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

The discontinued operations presented in the accompanying consolidated financial statements and notes primarily reflect gains in 2012 associated with certain of our former Venezuela operations. (See Note 3 – 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

We consolidate variable interest entities (VIEs) of which we are the primary beneficiary. The primary beneficiary of a VIE is the entity that has both (1) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (2) the obligation to absorb losses or the right to receive benefits that could be significant to the VIE. As of September 30, 2013, we consolidate the following VIEs:

Gulfstar

During the second quarter of 2013, a third party contributed $187 million to Gulfstar One LLC (Gulfstar) in exchange for a 49 percent ownership interest in Gulfstar. This contribution was based on 49 percent of WPZ’s estimated cumulative net investment to date. The $187 million was then distributed to WPZ. Following this transaction, WPZ owns a 51 percent interest in Gulfstar, 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’s economic performance. WPZ, as construction agent for Gulfstar, is designing, constructing, and 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 mid-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 $400 million, which will be funded with capital contributions from WPZ and the other equity partner, proportional to ownership interest. 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.

Notes (Continued)

Constitution

During the second quarter of 2013, a third party contributed $4 million to Constitution in exchange for a 10 percent ownership interest in Constitution. This contribution was based on 10 percent of Constitution’s contributed capital to date. The $4 million was then distributed to WPZ. Following this transaction, 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 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 March 2015 and estimates the total remaining construction costs of the project to be less than $625 million, which will be funded with capital contributions from WPZ and the other equity partners, proportional to ownership interest.

Bluegrass Pipeline

We own a 50 percent interest in Bluegrass Pipeline, a subsidiary that, due to insufficient equity to finance activities during its development stage, is a VIE. We are the primary beneficiary because we have the power to direct the activities of the project that most significantly impact its economic performance until the first developmental stage milestone is met; we have the power to direct whether the project moves forward. We and our partner plan to construct an NGL pipeline connecting 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. Pre-construction activities are under way and the project is planned to be in service in late 2015. This development stage entity is currently operating under a preliminary activities budget that governs the spending levels through February 28, 2014. Prior to that time, certain elections by either partner could change the relative ownership of the entity, impact the continued development of the project, and/or revise the determination of the primary beneficiary. The remaining amount that has been projected for spending under the preliminary activities budget is less than $140 million, and will be funded by us and our partner, proportional to ownership interest. Continued investment in this project beyond the preliminary activities stage will require additional significant capital contributions. Our Board of Directors has approved our continued investment in this project.

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:



	September 30, 2013			December 31, 2012			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	58		$	8		Cash and cash equivalents
Construction in progress	897			556			Property, plant and equipment, at cost
Accounts payable	(135		)	(128		)	Accounts payable
Construction retainage	(2		)	—			Accrued liabilities
Deferred revenue associated with customer advance payments	(110		)	(109		)	Other noncurrent liabilities

Notes (Continued)

Nonconsolidated VIEs

We have also identified certain interests in VIEs where 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 $492 million at September 30, 2013.

Caiman II

WPZ’s 47.5 percent-owned equity-method investment in Caiman Energy II, LLC (Caiman II) has been determined to be a VIE because it has insufficient equity to finance activities during the construction stage of the Blue Racer Midstream joint project, which is 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. 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 $380 million of total contributions that we have committed to make. At September 30, 2013, the carrying value of our investment in Caiman II was $257 million, which substantially reflects our contributions to date.

Moss Lake

Our equity-method investment in Moss Lake Fractionation LLC (Moss Lake) is a VIE because it has insufficient equity to finance activities during its development stage. We currently own 50 percent of this joint project which plans to construct a new large-scale fractionation plant, expand natural gas liquids storage facilities in Louisiana and construct a pipeline connecting these facilities to the Bluegrass Pipeline. We are not the primary beneficiary 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. The carrying value of our investment in Moss Lake at September 30, 2013, was $2 million, which represents our contributions to date. The amount we project for spending in order to fund our proportional share of the preliminary activities budget through February 28, 2014, is $52 million. Continued investment in this project beyond the preliminary activities stage will require additional significant capital contributions.

Note 3 – Discontinued Operations

Income (loss) from discontinued operations for the three and nine months ended September 30, 2013, includes a $3 million and $15 million, respectively, pre-tax charge resulting from an unfavorable ruling associated with our former Alaska refinery related to the Trans-Alaska Pipeline System Quality Bank.

Income (loss) from discontinued operations for the nine months ended September 30, 2012, includes a $144 million gain on reconsolidation related to our majority ownership in entities (the Wilpro entities) that owned and operated the El Furrial and PIGAP II gas compression facilities prior to their expropriation by the Venezuelan government in May 2009. We deconsolidated the Wilpro entities in 2009. In 2012, the El Furrial and PIGAP II assets were sold as part of a settlement related to the 2009 expropriation of these assets. Upon closing, the lenders that had provided financing for these operations were repaid in full, and the Wilpro entities received $98 million in cash and the right to receive quarterly cash installments of $15 million (receivable) plus interest through the first quarter of 2016. Following the settlement and repayment in full of the lenders, we reestablished control and, therefore, reconsolidated the Wilpro entities and recognized the gain on reconsolidation. This gain reflected our share of the cash, including cash received in the settlement, and the estimated fair value of the receivable held by the Wilpro entities at the time of reconsolidation. See Note 11 – Fair Value Measurements for a further discussion of this receivable.

Notes (Continued)

Note 4 – Asset Sales and Other Accruals

On June 13, 2013, an explosion and fire occurred at WPZ’s Geismar olefins plant located south of Baton Rouge, Louisiana, in an industrial complex, that resulted in the tragic deaths of two employees and injuries of additional employees and contractors. 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.

We have expensed $4 million and $10 million during the three and nine months ended September 30, 2013, respectively, of costs under our insurance deductibles in operating and maintenance expenses in the Consolidated Statement of Income. Recoveries under our business interruption policy will be recognized upon resolution of any contingencies with the insurer associated with the claim. Through September 30, 2013, we have recognized $50 million of insurance recoveries related to this incident as a gain to other (income) expense – net within costs and expenses in our Consolidated Statement of Income.

Included in selling, general, and administrative expenses are charges of $6 million and $14 million during the three and nine months ended September 30, 2012, respectively, related to our engagement of a consulting firm to assist in better aligning resources to support our business strategy following the spin-off of WPX Energy, Inc. (WPX). During the second quarter of 2012, we incurred acquisition transaction costs of $16 million related to the acquisition of 100 percent of the ownership interests in Caiman Eastern Midstream, LLC. These costs are also included in selling, general, and administrative expenses.

Other (income) expense – net within costs and expenses, in addition to the insurance recoveries mentioned above, includes:

•

Charges of $9 million and $15 million for the three and nine months ended September 30, 2013, respectively, related to the portion of the Eminence abandonment regulatory asset that will not be recovered through rates, pursuant to Transco’s agreement in principle associated with its general rate case filing (See Note 12 – Contingent Liabilities.). We also recognized income of $3 million and $15 million for the three and nine months ended September 30, 2013, respectively, related to insurance recoveries associated with this event;


•	Charges of $2 million during the nine months ended September 30, 2013 and $2 million and $17 million during the three and nine months ended September 30, 2012, respectively, related to project development costs associated with natural gas pipeline expansion projects;


•	A $9 million accrued loss in the three and nine months ended September 30, 2013 for a contingent liability associated with a pending producer claim against us;


•	Charges of $8 million and $15 million during the three and nine months ended September 30, 2013 and $2 million and $5 million during the three and nine months ended September 30, 2012 related to the amortization of regulatory assets associated with asset retirement obligations.

Notes (Continued)

Other investing income – net includes $11 million and $37 million of interest income for the three and nine months ended September 30, 2013, respectively, associated with a receivable related to the sale of certain former Venezuela assets (see Note 3 – Discontinued Operations). This amount reflects a current year increase in yield associated with a revision in our estimate of the cash flows expected to be received as a result of continued timely payment by the counterparty. In the nine months ended September 30, 2012, other investing income – net includes $63 million of income, including $10 million of interest, related to the 2010 sale of our interest in Accroven SRL. As part of a settlement regarding certain Venezuelan assets in the first quarter of 2012 (see Note 3 – Discontinued Operations), we also received payment for all outstanding balances due from this sale, including interest. Income had previously been recognized upon receipt of payments, as future collections were not reasonably assured.

Also included in other investing income – net for the nine months ended September 30, 2013, is a $26 million gain resulting from Access Midstream Partners’ equity issuance in April 2013. This equity issuance resulted in the dilution of our ownership interest from approximately 24 percent to 23 percent, which is accounted for as though we sold a portion of our investment.

Note 5 – Provision (Benefit) for Income Taxes

The provision (benefit) for income taxes includes:



	Three months ended September 30,					Nine months ended September 30,
	2013		2012			2013			2012
	(Millions)					(Millions)
Current:
Federal	$	25	$	58		$	(47	)	$	112
State	—		10			3			18
Foreign	2		6			3			30
	27		74			(41		)	160
Deferred:
Federal	21		6			233			123
State	9		(3		)	41			(9		)
Foreign	5		—			27			7
	35		3			301			121
Total provision (benefit)	$	62	$	77		$	260		$	281

The effective income tax rate for the total provision for the three months ended September 30, 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.

The effective income tax rate for the total provision for the nine months ended September 30, 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. The 2013 deferred provision includes $10 million related to the impact of a second-quarter Texas franchise tax law change, net of federal benefit.

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

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

During the first quarter of 2013, we finalized a settlement with the Internal Revenue Service (IRS) on tax matters related to the IRS’s examination of our 2009 and 2010 consolidated corporate income tax returns. We recorded a tax

Notes (Continued)

provision of approximately $2 million related to these matters during the third quarter of 2012. With respect to the examined years, we made cash payments of $12 million to the IRS in February of 2013.

With the spin-off of WPX on December 31, 2011, WPX entered into a tax sharing agreement with us under which we are generally liable for all U.S. federal, state, local and foreign income taxes attributable to WPX with respect to taxable periods ending on or before the distribution date. We are also principally responsible for managing any income tax audits by the various tax jurisdictions for pre-spin-off periods. In 2012, we prepared pro forma tax returns for each tax period in which WPX or any of its subsidiaries were combined or consolidated with us. In the first quarter of 2013, we reimbursed WPX a net $2 million for the additional losses shown on the pro forma tax returns, offset with additional tax resulting from the 2009 to 2010 IRS settlement.

On September 13, 2013, the IRS issued final regulations providing guidance on the treatment of amounts paid to acquire, produce or improve tangible property and proposed regulations providing guidance on the dispositions of such property. The implementation date for these regulations is January 1, 2014. Changes for tax treatment elected by us or required by the regulations will generally be effective prospectively; however, implementation of many of the regulations’ provisions will require a calculation of the cumulative effect of the changes on prior years, and it is expected that such amount will have to be included in the determination of our taxable income in 2014, or possibly over a four-year period beginning in 2014. The IRS is expected to issue additional procedural guidance regarding 2014 tax return filing requirements and how the requirements may be implemented for the gas transmission and distribution industry. Since the changes will affect the timing for deducting expenditures for tax purposes, the impact of implementation will be reflected in the amount of income taxes payable or receivable, cash flows from operations and deferred taxes beginning in 2014, with no net tax provision effect. Pending the issuance of additional procedural guidance from the IRS, we cannot at this time estimate the impact of implementing the regulations.

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.

On October 30, 2013, WPZ announced its intent to pursue an agreement to acquire certain of our Canadian operations. As a result, we no longer consider the undistributed earnings from these foreign operations to be permanently reinvested and thus expect to recognize approximately $200 million of deferred income tax expense in the fourth quarter of 2013. Of this amount, we estimate approximately $140 million will be characterized as a current income tax liability upon consummation of the proposed transaction.

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



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(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	$	143	$	152	$	454	$	572
Basic weighted-average shares	683,274		626,809		682,744		613,888
Effect of dilutive securities:
Nonvested restricted stock units	1,901		2,490		1,975		2,721
Stock options	2,113		2,535		2,169		2,695
Convertible debentures	18		185		119		461
Diluted weighted-average shares	687,306		632,019		687,007		619,765
Earnings (loss) per common share from continuing operations:
Basic	$	.21	$	.25	$	.66	$	.94
Diluted	$	.20	$	.25	$	.66	$	.93

Notes (Continued)

Note 7 – Employee Benefit Plans

Net periodic benefit cost is as follows:



	Pension Benefits
	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
	(Millions)
Components of net periodic benefit cost:
Service cost	$	11		$	10		$	33		$	29
Interest cost	12			14			38			42
Expected return on plan assets	(15		)	(16		)	(45		)	(48		)
Amortization of prior service cost	1			—			1			—
Amortization of net actuarial loss	15			13			45			40
Net actuarial loss from settlements	—			2			—			4
Net periodic benefit cost	$	24		$	23		$	72		$	67



	Other Postretirement Benefits
	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
	(Millions)
Components of net periodic benefit cost:
Service cost	$	1		$	1		$	2		$	2
Interest cost	2			4			8			10
Expected return on plan assets	(3		)	(3		)	(7		)	(7		)
Amortization of prior service credit	(3		)	(2		)	(7		)	(5		)
Amortization of net actuarial loss	1			2			4			6
Amortization of regulatory liability	1			—			1			—
Net periodic benefit cost	$	(1	)	$	2		$	1		$	6

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

Amounts recognized in net regulatory liabilities include:



	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
	(Millions)
Amortization of prior service credit	$	(1	)	$	(2	)	$	(4	)	$	(4	)
Amortization of net actuarial loss	—			1			2			4

Notes (Continued)

During the third quarter of 2013, our other postretirement benefit plan was amended, which resulted in a remeasurement of the plan’s funded status. The overall impact of the remeasurement was to reduce our liability reflecting the plan’s funded status by $121 million, with $59 million of the decrease directly attributable to the plan amendment and $62 million due to other actuarial gains through the remeasurement date. The decrease in our liability reflecting the plan’s funded status is offset by increases to accumulated other comprehensive income (loss) and net regulatory liabilities.

During the nine months ended September 30, 2013, we contributed $92 million to our pension plans and $6 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $2 million to our other postretirement benefit plans in the remainder of 2013.

Note 8 – Inventories



	September 30, 2013		December 31, 2012
	(Millions)
Natural gas liquids, olefins, and natural gas in underground storage	$	148	$	97
Materials, supplies, and other	82		78
	$	230	$	175

Note 9 – Debt and Banking Arrangements

Credit Facilities

On July 31, 2013, we amended our $900 million and WPZ’s $2.4 billion credit facilities to increase the aggregate commitments to $1.5 billion and $2.5 billion, respectively and extend the maturity dates for both credit facilities to July 31, 2018. Additionally, Transco and Northwest Pipeline are each able to borrow up to $500 million under the amended WPZ credit facility to the extent not otherwise utilized by the other co-borrowers. Both credit facilities may also, under certain conditions, be increased up to an additional $500 million. As a result of the modifications, the previously deferred fees and costs related to these facilities are being amortized over the term of the new arrangements.

At September 30, 2013, 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 September 30, 2013, no letters of credit have been issued and no loans are outstanding on these credit facilities. We have issued letters of credit totaling $17 million as of September 30, 2013, under certain bilateral bank agreements.

Commercial Paper Program

In March 2013, WPZ initiated a commercial paper program. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. Proceeds from these notes are used for general partnership purposes, including funding capital expenditures, working capital, and partnership distributions. At September 30, 2013, WPZ has $371 million in commercial paper outstanding at a weighted average interest rate of 0.41 percent.

Notes (Continued)

Note 10 – Stockholders’ Equity

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, 2012	$	(1	)	$	169		$	(530	)	$	(362	)
Other comprehensive income (loss) before reclassifications	1			(31		)	27			(3		)
Amounts reclassified from accumulated other comprehensive income (loss)	(1		)	—			28			27
Other comprehensive income (loss)	—			(31		)	55			24
Balance at September 30, 2013	$	(1	)	$	138		$	(475	)	$	(338	)

Reclassifications out of accumulated other comprehensive income (loss) are presented in the following table by component for the nine months ended September 30, 2013:



Component	Reclassifications			Classification
	(Millions)
Cash flow hedges:
Energy commodity contracts	$	(1	)	Product sales
Total cash flow hedges	(1		)

Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit cost	(2		)	Note 7 – Employee Benefit Plans
Amortization of actuarial (gain) loss included in net periodic benefit cost	47			Note 7 – Employee Benefit Plans
Total pension and other postretirement benefits	45

Reclassifications before income tax	44
Income tax benefit	(17		)	Provision (benefit) for income taxes
Reclassifications during the period	$	27

Notes (Continued)

Note 11 – Fair Value Measurements

The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, 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 September 30, 2013:
Measured on a recurring basis:
ARO Trust investments	$	31		$	31		$	31	$	—		$	—
Energy derivatives assets not designated as hedging instruments	6			6			—		1			5
Energy derivatives liabilities not designated as hedging instruments	(3		)	(3		)	—		(1		)	(2		)
Additional disclosures:
Notes receivable and other	82			148			1		7			140
Long-term debt, including current portion (a)	(10,358		)	(11,026		)	—		(11,026		)	—
Guarantee	(32		)	(29		)	—		(29		)	—
Assets (liabilities) at December 31, 2012:
Measured on a recurring basis:
ARO Trust investments	$	18		$	18		$	18	$	—		$	—
Energy derivatives assets not designated as hedging instruments	5			5			—		—			5
Energy derivatives liabilities not designated as hedging instruments	(1		)	(1		)	—		—			(1		)
Additional disclosures:
Notes receivable and other	95			138			2		8			128
Long-term debt, including current portion (a)	(10,734		)	(12,388		)	—		(12,388		)	—
Guarantee	(33		)	(31		)	—		(31		)	—

(a) Excludes capital leases

Fair Value Methods

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

Assets and liabilities measured at fair value on a recurring basis

ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its 2008 rate case settlement, into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted 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.

Notes (Continued)

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 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 nine months ended September 30, 2013 or 2012.

Additional fair value disclosures

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

Venezuela assets (see Note 3 – Discontinued Operations). 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 $105 million at September 30, 2013. The carrying value of this receivable is $38 million at September 30, 2013. The current and noncurrent portions are reported in accounts and notes receivable and regulatory assets, deferred charges, and other, respectively, in the Consolidated Balance Sheet.

Notes receivable and other also includes a receivable from our former affiliate, WPX (see Note 12 – 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, 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.

Notes (Continued)

Regarding our previously described guarantee of Wiltel’s lease performance, the maximum potential exposure is approximately $36 million at September 30, 2013 and December 31, 2012. Our exposure declines systematically throughout the remaining term of WilTel’s obligation.

We have provided guarantees in the event of nonpayment by our previously owned subsidiary, WPX, on certain contracts, primarily a natural gas purchase contract extending through 2023. We estimate the maximum undiscounted potential future payment obligation under these remaining guarantees is approximately $76 million at September 30, 2013. Our recorded liability for these guarantees, which considers our estimate of the fair value of the guarantees, is insignificant.

Note 12 – 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 continues to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. WPX and certain California utilities have agreed in principle to resolve WPX’s collection of accrued interest from counterparties as well as WPX’s payment of accrued interest on refund amounts. As currently contemplated by the parties, the settlement, which is subject to FERC and California regulatory approval, would resolve most of WPX’s legal issues arising from the 2000-2001 California Energy Crisis. We currently have a net receivable from WPX related to these matters.

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.

Notes (Continued)

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 Occupational Safety and Health Administration, the Chemical Safety Board, and the U.S. Environmental Protection Agency (EPA) to conduct investigations to determine the cause of the incident. On June 28, 2013, the Louisiana Department of Environmental Quality 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. 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 contracted with Gulsby Engineering Inc. (Gulsby) and Gulsby-Bay (a joint venture between Gulsby and Bay Ltd.) for the construction of certain gas processing plants in Louisiana. National American Insurance Company (NAICO) and American Home Assurance Company provided payment and performance bonds for the projects. In 2001, the contractors and sureties filed multiple cases in Louisiana and Texas against Gulf Liquids and us.

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

From May through October 2007, the court entered seven post-trial orders in the case (interlocutory orders) which, among other things, overruled the verdict award of tort and punitive damages as well as any damages against us. The court also denied the plaintiffs’ claims for attorneys’ fees. On January 28, 2008, the court issued its judgment awarding damages against Gulf Liquids of approximately $11 million in favor of Gulsby and approximately $4 million in favor of Gulsby-Bay. Gulf Liquids, Gulsby, Gulsby-Bay, Bay Ltd., and NAICO appealed the judgment. In February 2009, we settled with certain of these parties and reduced our accrued liability as of December 31, 2008, by $43 million, including $11 million of interest. On February 17, 2011, the Texas Court of Appeals upheld the dismissals of the tort and punitive damages claims. As a result, we reduced our accrued liability as of December 31, 2011 by $33 million, including $14 million of interest. The Texas Court of Appeals also reversed and remanded the remaining claims for further proceedings. None of the parties filed a petition for review in the Texas Supreme Court. On May 8, 2012, the Texas Court of Appeals issued its mandate remanding the original breach of contract claims involving Gulsby and attorney fee claims (the remaining claims) to trial court. Trial is set for October 14, 2014.

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

Notes (Continued)

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. Our claims against FHRA and their claims against us remain outstanding. We and FHRA filed motions for summary judgment on the other’s claims, but the motions are unlikely to resolve all the outstanding claims.

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 2013, ADEC informed FHRA and us that it 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. As such, we will likely be required to contribute some amount, whether to reimburse the State, to reimburse FHRA, or to comply with an ADEC order. Due to the ongoing assessment of the level and extent of sulfolane contamination and the ultimate cost of remediation and division of costs between the named responsible parties, we are unable to estimate a range of liability at this time.

Other

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

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 our prior rate proceeding. 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 that would resolve all issues in this proceeding without the need for a hearing after reaching an agreement in principle with the participants. The stipulation and agreement is subject to review and approval by the FERC. We have provided a reserve for rate refunds which we believe is adequate for any refunds that may be required.

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 September 30, 2013, we have accrued liabilities totaling $45 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered and the final cleanup standards mandated by the EPA and other governmental authorities.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating

Notes (Continued)

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.

Continuing operations

Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At September 30, 2013, we have accrued liabilities of $11 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At September 30, 2013, 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 the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.


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


•	Former petroleum products and natural gas pipelines;


•	Former petroleum refining facilities;


•	Former exploration and production and mining operations;


•	Former electricity and natural gas marketing and trading operations.

At September 30, 2013, we have accrued environmental liabilities of $27 million related to these matters.

Other Divestiture Indemnifications

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

At September 30, 2013, other than as previously disclosed, we are not aware of any material claims involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.

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

Notes (Continued)

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.

Note 13 – 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 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.

Notes (Continued)

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



	Williams Partners		Williams NGL & Petchem Services			Access Midstream Partners		Other		Eliminations			Total
	(Millions)
Three months ended September 30, 2013
Segment revenues:
Service revenues
External	$	731	$	—		$	—	$	5	$	—		$	736
Internal	—		—			—		2		(2		)	—
Total service revenues	731		—			—		7		(2		)	736
Product sales
External	855		32			—		—		—			887
Internal	—		27			—		—		(27		)	—
Total product sales	855		59			—		—		(27		)	887
Total revenues	$	1,586	$	59		$	—	$	7	$	(29	)	$	1,623
Segment profit (loss)	$	405	$	(2	)	$	6	$	3				$	412
Less:
Equity earnings (losses)	31		—			6		—					37
Income (loss) from investments	—		(1		)	—		—					(1		)
Segment operating income (loss)	$	374	$	(1	)	$	—	$	3				376
General corporate expenses													(40		)
Operating income (loss)													$	336

Three months ended September 30, 2012
Segment revenues:
Service revenues
External	$	668	$	2		$	—	$	5	$	—		$	675
Internal	—		—			—		2		(2		)	—
Total service revenues	668		2			—		7		(2		)	675
Product sales
External	1,049		28			—		—		—			1,077
Internal	—		32			—		—		(32		)	—
Total product sales	1,049		60			—		—		(32		)	1,077
Total revenues	$	1,717	$	62		$	—	$	7	$	(34	)	$	1,752
Segment profit (loss)	$	429	$	16		$	—	$	1				$	446
Less:
Equity earnings (losses)	30		—			—		—					30
Segment operating income (loss)	$	399	$	16		$	—	$	1				416
General corporate expenses													(43		)
Operating income (loss)													$	373

Notes (Continued)



	Williams Partners		Williams NGL & Petchem Services			Access Midstream Partners		Other		Eliminations			Total
	(Millions)
Nine months ended September 30, 2013
Segment revenues:
Service revenues
External	$	2,147	$	3		$	—	$	13	$	—		$	2,163
Internal	—		—			—		8		(8		)	—
Total service revenues	2,147		3			—		21		(8		)	2,163
Product sales
External	2,922		115			—		—		—			3,037
Internal	—		103			—		—		(103		)	—
Total product sales	2,922		218			—		—		(103		)	3,037
Total revenues	$	5,069	$	221		$	—	$	21	$	(111	)	$	5,200
Segment profit (loss)	$	1,264	$	56		$	35	$	—				$	1,355
Less:
Equity earnings (losses)	84		—			9		—					93
Income (loss) from investments	—		(3		)	26		—					23
Segment operating income (loss)	$	1,180	$	59		$	—	$	—				1,239
General corporate expenses													(127		)
Operating income (loss)													$	1,112

Nine months ended September 30, 2012
Segment revenues:
Service revenues
External	$	2,005	$	2		$	—	$	12	$	—		$	2,019
Internal	—		—			—		8		(8		)	—
Total service revenues	2,005		2			—		20		(8		)	2,019
Product sales
External	3,497		101			—		—		—			3,598
Internal	—		98			—		—		(98		)	—
Total product sales	3,497		199			—		—		(98		)	3,598
Total revenues	$	5,502	$	201		$	—	$	20	$	(106	)	$	5,617
Segment profit (loss)	$	1,371	$	72		$	—	$	61				$	1,504
Less:
Equity earnings (losses)	87		—			—		1					88
Income (loss) from investments	—		(2		)	—		53					51
Segment operating income (loss)	$	1,284	$	74		$	—	$	7				1,365
General corporate expenses													(133		)
Operating income (loss)													$	1,232
September 30, 2013
Total assets	$	21,633	$	1,543		$	2,162	$	1,839	$	(722	)	$	26,455
December 31, 2012
Total assets	$	19,709	$	1,134		$	2,187	$	1,782	$	(485	)	$	24,327

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 (NGLs), and olefins. Our operations are located principally in the United States, but span from the deepwater Gulf of Mexico to the Canadian oil sands, and are organized into the Williams Partners, Williams NGL & Petchem Services, and Access Midstream Partners reportable segments. All remaining business activities are included in Other.

Williams Partners

Williams Partners includes Williams Partners L.P. (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. As of September 30, 2013, we own approximately 64 percent of the interests in WPZ, including the interests of the general partner, which is wholly owned by us, and incentive distribution rights.

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

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

Williams NGL & Petchem Services

Williams NGL & Petchem Services includes our oil sands offgas processing plant near Fort McMurray, Alberta and our NGL/olefin fractionation facility and butylene/butane (B/B) splitter facility at Redwater, Alberta. We produce NGLs and propylene. Our NGL products include propane, normal butane, isobutane/butylene (butylene), and condensate. Williams NGL & Petchem Services also includes Bluegrass Pipeline Company LLC (Bluegrass Pipeline), a new joint project, 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.

Access Midstream Partners

Access Midstream Partners includes our equity method investment in Access Midstream Partners L.P. (ACMP), acquired in December 2012. As of September 30, 2013, this investment includes a 23 percent limited partner interest in ACMP and a 50 percent indirect interest in Access Midstream Partners GP L.L.C. (Access GP), including incentive distribution rights. ACMP is a publicly traded master limited partnership that owns, operates, develops, and acquires

Management’s Discussion and Analysis (Continued)

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 our 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 2012 Annual Report on Form 10-K, filed February 27, 2013.

Proposed Dropdown

On October 30, 2013, WPZ announced its intent to pursue an agreement to acquire certain of our Canadian operations, including our oil sands offgas processing plant near Fort McMurray, an NGL/olefin fractionation facility and butylene/butane splitter facility at Redwater, and the Boreal pipeline. WPZ expects to fund the transaction through the issuance of a new class of limited-partner units to us. These units will receive quarterly distributions of additional paid-in-kind units, all of which will be convertible to common units at a future date. The transaction is subject to execution of an agreement, review and recommendation by the Conflicts Committee of the general partner of WPZ, and approval of both our and WPZ’s Board of Directors.

Dividends

In September 2013, we paid a regular quarterly dividend of $0.36625 per share, which was 17.2 percent higher than the same period last year and 3.9 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 2013, 2014, and 2015.

Overview of Nine Months Ended September 30, 2013

Income (loss) from continuing operations attributable to The Williams Companies, Inc., for the nine months ended September 30, 2013, changed unfavorably by $118 million compared to the nine months ended September 30, 2012. This change primarily reflects:

•

A $104 million unfavorable change in segment operating income at Williams Partners primarily due to lower NGL margins driven by reduced ethane recoveries and decreases in average NGL per-unit sales prices, and higher natural gas prices, along with higher operating costs associated with ongoing growth. Partially offsetting these unfavorable changes was an increase in fee revenues (see Results of Operations – Segments, Williams Partners);

•

The absence of $63 million of income recognized in 2012 related to the 2010 sale of our interest in Accroven SRL. This is partially offset by $37 million of interest income recorded in 2013 associated with a receivable related to the sale of certain former Venezuela assets and a gain of $26 million resulting from Access Midstream Partners’ equity issuance in April 2013 (see Note 4 – Asset Sales and Other Accruals of Notes to Consolidated Financial Statements).

See additional discussion in Results of Operations.

Williams Partners

Geismar Incident

On June 13, 2013, an explosion and fire occurred at WPZ’s Geismar olefins plant located south of Baton Rouge, Louisiana, in an industrial complex, which resulted in the tragic deaths of two employees and injuries of additional employees and contractors. 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:

Management’s Discussion and Analysis (Continued)


•	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.

We have been focused on conducting the causal investigations with the Occupational Safety and Health Administration and the Chemical Safety Board. We have expensed $4 million and $10 million during the three and nine months ended September 30, 2013, respectively, of costs under our insurance deductibles in operating and maintenance expenses in the Consolidated Statement of Income. Recoveries under our business interruption policy will be recognized upon resolution of any contingencies with the insurer associated with the claim. Through September 30, 2013, we have recognized $50 million of insurance recoveries related to this incident as a gain to other (income) expense - net within costs and expenses in our Consolidated Statement of Income.

Following the repair and plant expansion, the Geismar plant is expected to be in operation by April 2014. We expect our insurance coverage will significantly mitigate our financial loss. We currently estimate $343 million of total cash recoveries from insurers related to business interruption losses. Our current damage assessment and repair plan reaffirmed the previously estimated cost of $102 million to repair the plant. We will be impacted by certain uninsured losses, including amounts associated with the 60-day waiting period for business interruption, as well as other deductibles 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.

Marcellus Shale

In the second quarter of 2013, we completed an expansion to our natural gas gathering system, processing facilities, and fractionator in our Ohio Valley Midstream business of the Marcellus Shale including a third turbo-expander at our Fort Beeler facility, which added 200 MMcf/d of processing capacity. In the first half of 2014, we expect to add fractionation capacity at our Moundsville fractionators bringing the NGL handling capacity to approximately 43 thousand barrels per day (Mbbls/d), complete our first turbo-expander at our Oak Grove facility to add 200 MMcf/d of processing capacity, and finalize the construction of our first deethanizer with a capacity of 40 Mbbls/d and the associated 50-mile ethane line to Houston, Pennsylvania.

Overland Pass Pipeline

Through our equity investment in Overland Pass Pipeline Company LLC (OPPL), we completed the construction of a pipeline expansion in the second quarter of 2013, which increased the pipeline’s capacity to 255 Mbbls/d. In addition, a new connection was completed in April 2013 to bring new volumes to OPPL from the Bakken Shale in the Williston basin.

Mid-South

The Mid-South expansion project involves an expansion of Transco’s mainline from Station 85 in Choctaw County, Alabama to markets as far downstream as North Carolina. In August 2011, we received approval from the FERC for the project. We placed the first phase of the project into service in the third quarter of 2012, which increased capacity by 95 thousand dekatherms per day (Mdth/d). The second phase was placed into service in the second quarter of 2013, which increased capacity by an additional 130 Mdth/d.

Management’s Discussion and Analysis (Continued)

Three Rivers Midstream

In April 2013, we announced an agreement to launch a new midstream joint project to provide gas gathering and gas processing services for production located in northwest Pennsylvania. The project will invest in both wet-gas handling infrastructure and dry-gas infrastructure serving the Marcellus and Utica Shale wells in the area. We will initially own substantially all of the new project, Three Rivers Midstream, and operate the assets. Our partner has the right to invest capital and increase its ownership to a maximum of 50 percent by July 2015. The current estimate of the total cost of the project is expected to be approximately $150 million. This does not include the cost of the gathering system, which will be determined in the future based upon the producers’ needs. Subsequent capital investment is expected as the business and scale increases.

Three Rivers Midstream has signed a long-term fee-based dedicated gathering and processing agreement for our partner’s production in the area, including approximately 275,000 dedicated acres. Three Rivers Midstream plans to construct a 200 million cubic feet per day (MMcf/d) cryogenic gas processing plant and related facilities at a location to be determined. The initial plant is expected to be placed into service in mid-2015. The system is expected to be connected to two major proposed developments in Pennsylvania – our partner’s proposed ethylene cracker (feasibility study is in progress) in Beaver County and our joint project to develop the Bluegrass Pipeline system that would deliver Marcellus and Utica liquids to the Gulf Coast and export markets.

Gulfstar

Effective April 1, 2013, WPZ sold a 49 percent interest in Gulfstar One LLC (Gulfstar) to a third party for $187 million, representing their proportionate share of estimated capital expenditures to date for the construction of Gulfstar FPS™, which is a proprietary floating production system and has been under construction since late 2011. It is supported by multiple agreements with two major producers to provide production handling, export pipeline, oil and gas gathering and gas processing services for the Tubular Bells field development located in the eastern deepwater Gulf of Mexico. The Gulfstar FPS™ will tie into our wholly owned oil and gas gathering and gas processing systems in the eastern Gulf of Mexico. Gulfstar FPS™ is expected to have an initial capacity of 60 Mbbls/d, up to 200 MMcf/d of natural gas and the capability to provide seawater injection services. We expect Gulfstar FPS™ to be capable of serving as a central host facility for other deepwater prospects in the area. The project is expected to be in service in mid-2014.

Mid-Atlantic Connector

The Mid-Atlantic Connector Project involves an expansion of Transco’s mainline from an existing interconnection with East Tennessee Natural Gas in North Carolina to markets as far downstream as Maryland. In July 2011, we received approval from the FERC for the project. We placed the project into service in the first quarter of 2013, and it increased capacity by 142 Mdth/d.

Volume impacts in 2013

Due to unfavorable ethane economics, we reduced our recoveries of ethane in our plants during most of the first nine months of 2013, which resulted in 29 percent lower NGL production volumes and 46 percent lower NGL equity sales volumes in the first nine months of 2013 compared to the same period of 2012.

As a result of the Geismar Incident, ethylene sales volumes have decreased 96 percent and 41 percent for the three and nine months ended 2013, respectively, compared to the same period of 2012.

Volatile commodity prices

NGL margins were approximately 42 percent lower in the first nine months of 2013 compared to the same period of 2012 driven by reduced ethane recoveries, as previously mentioned, coupled with lower NGL prices and higher natural gas prices. However, our average per-unit composite NGL margin in the first nine months of 2013 has increased slightly compared to the same period of 2012 as the relative mix of NGL products produced has shifted to a greater proportion of higher-margin non-ethane products.

Management’s Discussion and Analysis (Continued)

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

Williams NGL & Petchem Services

Canadian PDH Facility

During the first quarter of 2013, we announced plans to build Canada’s first propane dehydrogenation (PDH) facility located in Alberta. The new PDH facility will produce approximately 1.1 billion pounds annually, significantly increasing Williams’ production of polymer-grade propylene currently at 180 million pounds. The expected start-up date for the PDH facility is the second quarter of 2017.

Bluegrass Pipeline and Moss Lake

In the second quarter of 2013, we finalized the formation of a joint project to develop the Bluegrass Pipeline. We own a 50 percent consolidated interest in 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. The pipeline would deliver mixed NGLs from these producing areas to proposed new fractionation and storage facilities, which would have connectivity to petrochemical facilities and product pipelines along the coasts of Louisiana and Texas. We are working to develop customer support for the pipeline, including the recently announced open season for capacity on Bluegrass Pipeline. The first phase of the project is expected to have a mixed NGLs take-away capacity of 200 Mbbls/d and is planned to be in service in late 2015. The second phase of the project is expected to increase capacity to 400 Mbbls/d.

Management’s Discussion and Analysis (Continued)

Through our 50 percent equity investment in Moss Lake Fractionation LLC, the project would also include constructing a new large-scale fractionation plant and expanding NGL storage facilities in Louisiana. In October 2013, we announced a related joint project, Moss Lake LPG Terminal, which explores the development of a new liquefied petroleum gas export terminal and related facilities on the Gulf Coast to provide customers access to international markets.

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 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, we expect the financial impact of the Geismar Incident will be significantly mitigated by our insurance policies. However, the timing of recognizing recoveries under our business interruption policy, as well as the effect of the 60-day waiting period, will likely cause a significant negative impact to our 2013 results.

In light of all of the above, our business plan for 2013 continues to reflect both significant capital investment and dividend growth. Our planned consolidated capital investments for 2013 total approximately $4.4 billion which we expect to fund primarily through cash on hand, cash flow from operations, and debt and equity issuances by WPZ. We also expect 20 percent growth in total 2013 dividends, which we expect to fund primarily with distributions received from WPZ. Our structure is designed to drive lower capital costs, enhance reliable access to capital markets, and create a greater ability to pursue development projects and acquisitions.

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


•	General economic, financial markets, or industry downturn;


•	Availability of capital;


•	Lower than expected levels of cash flow from operations;


•	Counterparty credit and performance risk;


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


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


•	Lower than anticipated energy commodity prices and margins;


•	Changes in the political and regulatory environments;


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

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

The following factors, among others, could impact our businesses in 2013.

Management’s Discussion and Analysis (Continued)

Williams Partners

Commodity price changes

We expect ethane prices to remain at current levels, which will result in continued ethane rejection across most of our systems. We further expect that the combination of lower NGL prices and higher natural gas prices will result in overall total NGL margins being lower than the previous year. NGL price changes have historically correlated somewhat with changes in the price of crude oil, although NGL, crude, and natural gas prices are highly volatile, and difficult to predict. NGL margins are highly dependent upon regional supply/demand balances of natural gas. 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.

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 rates in producing areas impact the amount of gas available for gathering and processing.

•

In Williams Partners’ onshore businesses, we anticipate significant growth compared to the prior year in our natural gas gathering volumes as our infrastructure grows to support drilling activities in the Marcellus Shale region. Based on less favorable producer economics in the western region, we expect a decrease in production and thus a lower supply of natural gas available to gather and process in 2013.


•	We anticipate equity NGL volumes in 2013 to be lower than 2012 primarily due to periods when we expect it will not be economical to recover ethane. In addition, our equity NGL volumes were also impacted by a change in a customer’s contract from percent-of-liquids to fee-based processing, with a portion of the fee representing a share of the associated NGL margins.


•	In Williams Partners’ businesses in the Gulf Coast, we expect lower production handling and crude transportation volumes compared to 2012, as production flowing through our Devils Tower facility declines.


•	We anticipate higher general and administrative, operating, and depreciation expense related to our growing operations in the Marcellus Shale area.

Eminence Storage Field leak

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

In September 2011, we filed an application with the FERC seeking authorization to abandon these four caverns. In February 2013, the FERC issued an order approving the abandonment. We estimate the total abandonment costs, which will be capital in nature, will be approximately $103 million, which is expected to be spent through the first half of 2014. As of September 30, 2013, we have incurred approximately $92 million of these abandonment costs. This estimate is subject to change as work progresses and additional information becomes known. Management considers these costs to be prudent costs incurred in the abandonment of these caverns. Consistent with the terms of the pending rate case, for the three and nine months ended September 30, 2013, we expensed $9 million and $15 million, respectively, related to the Eminence abandonment regulatory asset that will not be recovered in rates. We have also recognized income for the three and nine months ended September 30, 2013, of $3 million and $15 million, respectively, related to insurance recoveries associated with this event.

Management’s Discussion and Analysis (Continued)

Filing of rate cases

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 the hearing. On August 27, 2013, after reaching an agreement in principle with the participants, Transco filed with the FERC a stipulation and agreement that would resolve all issues in this proceeding without the need for a hearing. The stipulation and agreement is subject to review and approval by the FERC. We have provided a reserve for rate refunds which we believe is adequate for any refunds that may be required.

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

Williams NGL & Petchem Services

Commodity margin and volume changes

While per-unit margins are volatile and highly dependent upon continued demand within the global economy, we believe that our gross commodity margins will be comparable to 2012 levels. Volumes for the year are expected to be somewhat higher than 2012 levels. Canadian oil sands offgas continues to hold a distinct feedstock advantage over traditional crackers. We expect to benefit in the broader global petrochemical markets because of our strategic advantage in NGL and olefins production from oil sands.

Access Midstream Partners

Access Midstream Partners expects its annual distributions to unitholders will grow by approximately 15 percent in 2013 and 2014. We forecast that we will receive distributions of $92 million from our investment in Access Midstream Partners for 2013.

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.

Expansion Projects

We expect to invest total capital in 2013 among our business segments as follows:



	Low		High
	(Millions)
Segment:
Williams Partners	$	3,135	$	3,465
Williams NGL & Petchem Services	620		730

Our ongoing major expansion projects include the following:

Management’s Discussion and Analysis (Continued)

Williams Partners

Leidy Southeast

In September 2013, we filed an application with the FERC for Transco’s Leidy Line 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 main system from Station 85 in Alabama. We plan to place the project into service in December 2015, and expect to increase capacity by an additional 525 Mdth/d.

Mobile Bay South III

In July 2013, we filed an application with the FERC for 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 in April 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 new jointly-owned Constitution Pipeline. As of May 2013, we currently own 41 percent of Constitution Pipeline with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will be the operator of Constitution Pipeline. The new 120-mile Constitution Pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We plan to place the project into service in March 2015, 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 second half of 2014, and expect to increase capacity by 100 Mdth/d.

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 second half of 2014, with an expected capacity of 647 Mdth/d.

Virginia Southside

In December 2012, we filed an application with 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 in September 2015, and expect to increase capacity by 270 Mdth/d.

Northeast Supply Link

In November 2012, we received approval from the FERC to expand Transco’s existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. We plan to place the project into service in November 2013, and expect to increase capacity by an additional 250 Mdth/d.

Management’s Discussion and Analysis (Continued)

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 billion cubic feet per day (Bcf/d) by 2015, including capacity contributions from the Constitution Pipeline.

•

As previously discussed, we completed construction at our Fort Beeler facility in the Marcellus Shale, which added 200 MMcf/d of processing capacity in the second quarter of 2013. We have several significant projects under construction with targeted construction completion in the first half of 2014. We are completing a 43 Mbbls/d expansion of the Moundsville fractionator, 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. These projects are expected to provide the base facilities required to meet current contractual obligations.


•	Expansions to the Laurel Mountain Midstream, LLC (Laurel Mountain) gathering system infrastructure to increase the capacity to 700 MMcf/d by the end of 2015 through capital to be invested within 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 Energy II equity investment.

Gulfstar FPS™ Deepwater Project

We will design, construct, and install our Gulfstar FPS™, a spar-based floating production system that utilizes a standard design approach with a capacity of 60 Mbbls/d of oil, up to 200 MMcf/d of natural gas, and the capability to provide seawater injection services, as previously discussed. Construction is under way and the project is expected to be in service in mid-2014.

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 an earlier in-service date is warranted.

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, which is expected to occur in April 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 share of the Geismar production facility from the current 83.3 percent.

Keathley Canyon Connector™

Our equity investee which we operate, Discovery Producer Services LLC (Discovery), plans to construct, own, and operate a new 215-mile, 20-inch deepwater lateral pipeline in the central deepwater Gulf of Mexico. Discovery has signed long-term agreements with anchor customers for natural gas gathering and processing services for production from 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.

Management’s Discussion and Analysis (Continued)

Williams NGL & Petchem Services

Canadian PDH Facility

As previously discussed, we are planning to build a propane dehydrogenation (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.

Ethane Recovery Project

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

NGL Infrastructure Expansion

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

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 early 2015.

Bluegrass Pipeline

As previously discussed, in the second quarter we finalized the formation of a joint project to develop the Bluegrass Pipeline. Pre-construction activities are under way and the first phase of the project is planned to be in service in late 2015.

Management’s Discussion and Analysis (Continued)

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three and nine months ended September 30, 2013, compared to the three and nine months ended September 30, 2012. The results of operations by segment are discussed in further detail following this consolidated overview discussion.



	Three months ended September 30,								Nine months ended September 30,
	2013			2012			$ Change*	% Change*	2013			2012			$ Change*	% Change*
	(Millions)								(Millions)
Revenues:
Service revenues	$	736		$	675		+61	+9%	$	2,163		$	2,019		+144	+7%
Product sales	887			1,077			-190	-18%	3,037			3,598			-561	-16%
Total revenues	1,623			1,752			-129	-7%	5,200			5,617			-417	-7%
Costs and expenses:
Product costs	710			771			+61	+8%	2,301			2,628			+327	+12%
Operating and maintenance expenses	269			261			-8	-3%	820			766			-54	-7%
Depreciation and amortization expenses	207			196			-11	-6%	606			545			-61	-11%
Selling, general, and administrative expenses	130			137			+7	+5%	385			415			+30	+7%
Other (income) expense – net	(29		)	14			+43	NM	(24		)	31			+55	NM
Total costs and expenses	1,287			1,379					4,088			4,385
Operating income (loss)	336			373					1,112			1,232
Equity earnings (losses)	37			30			+7	+23%	93			88			+5	+6%
Interest expense	(124		)	(129		)	+5	+4%	(379		)	(388		)	+9	+2%
Other investing income – net	10			3			+7	NM	62			75			-13	-17%
Other income (expense) – net	1			—			+1	NM	1			(1		)	+2	NM
Income (loss) from continuing operations before income taxes	260			277					889			1,006
Provision (benefit) for income taxes	62			77			+15	+19%	260			281			+21	+7%
Income (loss) from continuing operations	198			200					629			725
Income (loss) from discontinued operations	(1		)	3			-4	NM	(10		)	138			-148	NM
Net income (loss)	197			203					619			863
Less: Net income attributable to noncontrolling interests	56			48			-8	-17%	175			153			-22	-14%
Net income (loss) attributable to The Williams Companies, Inc.	$	141		$	155				$	444		$	710



*	+ = 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 September 30, 2013 vs. three months ended September 30, 2012

The increase in service revenues is primarily due to higher fee revenues associated with the growth in the businesses acquired in the 2012 acquisitions of Caiman Eastern Midstream, LLC (Caiman Acquisition) and certain entities from Delphi Midstream Partners, LLC (Laser Acquisition). This growth includes higher gathering volumes from new well connections resulting from infrastructure additions, increased gathering rates associated with customer contract modifications, and contributions from the processing and fractionation facilities placed in service in the latter half of

Management’s Discussion and Analysis (Continued)

2012 and in 2013. Additionally, natural gas transportation fee revenues increased from expansion projects placed into service in 2012 and 2013 and new rates effective during first-quarter 2013. Partially offsetting these increases are lower fee revenues in the eastern Gulf Coast primarily driven by natural declines in Bass Lite and Blind Faith production area volumes, as well as decreased gathering and processing fee revenues driven by lower volumes in the Piceance and Four Corners areas.

The decrease in product sales is primarily due to lower olefin production revenues resulting from the loss of production as a result of the Geismar Incident. In addition, NGL production revenues decreased due to lower volumes primarily driven by reduced ethane recoveries and a change in a certain customer contract from percent-of-liquids to fee-based processing, as well as decreases in average ethane per-unit sales prices. Marketing revenues also decreased primarily due to lower NGL prices and lower crude oil and natural gas volumes, partially offset by higher crude oil prices and higher natural gas prices.

The decrease in product costs is primarily due to decreased olefin feedstock purchases as a result of the Geismar Incident. In addition, marketing purchases decreased resulting from lower NGL prices and lower crude oil and natural gas volumes, partially offset by higher crude oil prices and higher natural gas prices.

The increase in operating and maintenance expenses is primarily associated with the subsequent growth in the operations of the businesses acquired in the Caiman and Laser Acquisitions including increased pipeline maintenance and repair costs, as well as a scheduled third-quarter shutdown to conduct maintenance at Williams NGL & Petchem Services. These increases are partially offset by a decrease in compressor and pipeline maintenance expenses resulting from the absence of expenses related to the substantial completion of our natural gas pipeline integrity management plan during 2012 and lower operating costs in our Four Corners area related to the consolidation of certain operations.

The increase in depreciation and amortization expenses reflects increased depreciation expense in 2013 associated with the businesses acquired in 2012 and depreciation on subsequent infrastructure additions, partially offset by the absence of increased depreciation in 2012 on certain assets in the Gulf Coast region resulting from a change in the estimated useful lives.

The decrease in selling, general, and administrative expenses (SG&A) includes the absence of reorganization related costs in 2012 (see Note 4 – Asset Sales and Other Accruals of Notes to Consolidated Financial Statements).

The favorable changes in other (income) expense – net within operating income (loss) primarily include $50 million of income associated with insurance recoveries related to the Geismar Incident and $3 million of insurance recoveries related to the abandonment of certain Eminence storage assets. Partially offsetting these changes is a $9 million expense recognized in third-quarter 2013 related to the portion of certain of the Eminence abandonment regulatory asset that will not be recovered in rates and a $9 million accrued loss for a contingent liability associated with a pending producer claim against us.

The unfavorable change in operating income (loss) generally reflects lower olefin production margins, lower NGL production margins and a decrease in marketing margins, partially offset by increased fee revenues and the favorable changes in other (income) expense – net as described above.

The favorable change in equity earnings (losses) is primarily due to higher equity earnings at Access Midstream Partners due to the absence of this investment in 2012 and higher equity earnings from Laurel Mountain and Aux Sable Liquid Products LP (Aux Sable) driven by their higher operating results . These higher earnings are partially offset by lower equity earnings from Discovery driven by lower NGL margins resulting from decreased ethane recoveries.

Interest expense decreased due to an increase in interest capitalized related to construction projects primarily at Williams Partners, partially offset by an increase in interest incurred primarily due to an increase in borrowings.

The favorable change in other investing income – net is primarily due to $8 million higher interest income recorded in the third quarter of 2013 associated with a receivable related to the sale of certain former Venezuela assets (See Note 4 – Asset Sales and Other Accruals of Notes to Consolidated Financial Statements.)

Management’s Discussion and Analysis (Continued)

Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income in 2013. See Note 5 of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.

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

Nine months ended September 30, 2013 vs. nine months ended September 30, 2012

The increase in service revenues is primarily due to higher fee revenues associated with the growth in the businesses acquired in 2012, including higher volumes from new well connections resulting from infrastructure additions, a full nine month of operations from these businesses, increased gathering rates associated with customer contract modifications, as well as contributions from the processing and fractionation facilities placed in service in the latter half of 2012 and in 2013. Additionally, natural gas transportation fee revenues increased from expansion projects placed into service in 2012 and 2013 and new rates effective during first-quarter 2013. Partially offsetting these increases are decreased gathering and processing fee revenues primarily due to a natural decline in production volumes, primarily in the Piceance basin, and severe winter weather conditions in the first quarter of 2013 which prevented producers from delivering gas. In addition, fee revenues decreased in the eastern Gulf Coast primarily driven by natural declines in Bass Lite and Blind Faith production area volumes.

The decrease in product sales is primarily due to a decrease in NGL production revenues due to lower volumes primarily driven by reduced ethane recoveries and decreases in average NGL per-unit sales prices. Marketing revenues also decreased resulting from lower NGL prices and lower crude oil volumes, partially offset by higher natural gas volumes and prices. Also impacting the decrease are lower crude oil volumes related to natural declines in Bass Lite and Blind Faith production area and lower olefin production revenues primarily due to lower volumes from the loss of production as a result of the Geismar Incident, partially offset by higher per-unit sales prices.

The decrease in product costs is primarily due to lower marketing purchases resulting from lower NGL prices and lower crude oil volumes, partially offset by higher natural gas volumes and prices. In addition, olefin feedstock purchases decreased reflecting lower sales volumes and lower average per-unit feedstock costs. Costs associated with the production of NGLs also decreased primarily resulting from lower volumes, driven by lower ethane recoveries, partially offset by an increase in average natural gas prices.

The increase in operating and maintenance expenses is primarily associated with the subsequent growth in the operations of the businesses acquired in the Caiman and Laser Acquisitions including higher pipeline maintenance and repair costs, a scheduled third-quarter 2013 shutdown to conduct maintenance at Williams NGL & Petchem Services and $10 million of costs incurred under our insurance deductibles resulting from the Geismar Incident. These increases are partially offset by lower compressor and pipeline maintenance and repair expenses resulting from the absence of expenses related to the substantial completion of our natural gas pipeline integrity management plan during 2012 and lower operating costs in our Four Corners area related to the consolidation of certain operations.

The increase in depreciation and amortization expenses reflects a full nine months of depreciation expense in 2013 related to the Caiman and Laser Acquisitions and depreciation on subsequent infrastructure additions, partially offset by the absence of increased depreciation in 2012 on certain assets in the Gulf Coast region resulting from a change in the estimated useful lives.

The decrease in SG&A is primarily due to the absence of acquisition and transition costs incurred in 2012 and the absence of reorganization related costs in 2012 (see Note 4 – Asset Sales and Other Accruals of Notes to Consolidated Financial Statements).

Management’s Discussion and Analysis (Continued)

The favorable change in other (income) expense – net within operating income primarily includes $50 million of income associated with insurance recoveries related to the Geismar Incident, $15 million of insurance recoveries related to the abandonment of certain Eminence storage assets, and $17 million lower project development costs. Partially offsetting these changes is a $15 million expense recognized in 2013 related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates, a $9 million accrued loss for a contingent liability associated with a pending producer claim against us recognized in the third quarter of 2013, and the absence of a $6 million gain on the sale of equipment in the second quarter of 2012.

The unfavorable change in operating income (loss) generally reflects lower NGL production margins, higher operating costs, and lower olefin production margins, partially offset by increased fee revenues, and the favorable changes in other (income) expense – net as described above.

The favorable changes in equity earnings (losses) are primarily due to higher equity earnings from Laurel Mountain driven by higher operating results and higher equity earnings from Access Midstream Partners due to the absence of this investment in 2012, partially offset by lower equity earnings from Discovery due to lower NGL margins driven by decreased ethane recoveries and lower equity earnings at Aux Sable driven by lower NGL margins.

The unfavorable change in other investing income – net is primarily due to the absence of $63 million of income recognized in 2012, including $10 million of interest income, related to the 2010 sale of our interest in Accroven SRL. This is partially offset by $32 million of higher interest income recorded in 2013 associated with a receivable related to the sale of certain former Venezuela assets, as compared to 2012, and a gain of $26 million resulting from Access Midstream Partners’ equity issuance in April 2013. (See Note 4 – Asset Sales and Other Accruals of Notes to Consolidated Financial Statements.)

Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income in 2013. See Note 5 – 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.

Income (loss) from discontinued operations in 2013 primarily includes a $15 million charge resulting from an unfavorable ruling associated with our former Alaska refinery related to the Trans-Alaska Pipeline System Quality Bank. Income (loss) from discontinued operations in 2012 primarily includes a $144 million gain on reconsolidation following the sale of certain of our former Venezuela operations. (See Note 3 – Discontinued Operations of Notes to Consolidated Financial Statements.)

The unfavorable change in net income attributable to noncontrolling interests primarily reflects the noncontrolling interests’ share of WPZ income from Geismar in 2013, following the dropdown in November 2012, and our slightly decreased percentage of limited partner ownership of WPZ, partially offset by higher income allocated to the general partner associated with incentive distribution rights. It also reflects our partners’ share of increased interest income related to a receivable from the sale of certain former Venezuela assets. (See Note 4 – Asset Sales and Other Accruals of Notes to Consolidated Financial Statements.)

Management’s Discussion and Analysis (Continued)

Period-Over-Period Operating Results - Segments

Williams Partners



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(Millions)
Segment revenues	$	1,586	$	1,717	$	5,069	$	5,502
Segment profit	405		429		1,264		1,371

Three months ended September 30, 2013 vs. three months ended September 30, 2012

The decrease in segment revenues includes:


•	A $114 million decrease in olefin sales primarily due to the loss of production as a result of the Geismar Incident.

•

A $56 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $43 million due to lower volumes and a $13 million decrease associated with 5 percent lower average realized non-ethane per-unit sales prices and 32 percent lower average ethane per-unit sales prices. Equity ethane sales volumes are 68 percent lower primarily driven by reduced ethane recoveries, as previously mentioned. The decrease in both ethane and non-ethane volumes is also due to a change in a certain customer’s contract from percent-of-liquids to fee-based processing.


•	A $39 million decrease in marketing revenues primarily associated with lower NGL prices and lower crude oil and natural gas volumes, partially offset by higher crude oil prices and higher natural gas prices. The changes in marketing revenues are substantially offset by similar changes in marketing purchases.

•

A $63 million increase in fee revenues primarily due to $46 million higher fee revenues resulting from higher gathering volumes driven by new well connections related to infrastructure additions and increased gathering rates associated with customer contract modifications primarily in the Susquehanna Supply Hub and higher gathering volumes and contributions from the processing and fractionation facilities placed in service in the latter half of 2012 and in 2013 in the Ohio Valley Midstream business. Natural gas transportation revenues also increased $26 million from expansion projects placed into service in 2012 and 2013, as well as new rates effective in first-quarter 2013. Partially offsetting these increases is a $7 million decrease in gathering and processing revenues resulting from lower production in the Piceance basin and Four Corners areas. In addition, fee revenues decreased $8 million in the eastern Gulf Coast primarily driven by natural declines in Bass Lite and Blind Faith production area volumes.


•	A $10 million increase in other product sales primarily due to higher system management gas sales from our gas pipeline businesses (offset in segment costs and expenses).

The decrease in segment costs and expenses of $106 million includes:


•	A $38 million decrease in olefin feedstock purchases primarily due to the loss of production as a result of the Geismar Incident.


•	A $33 million decrease in marketing purchases primarily due to lower NGL prices and lower crude oil and natural gas volumes, partially offset by higher crude oil prices and higher natural gas prices (more than offset in marketing revenues).

Management’s Discussion and Analysis (Continued)


•	A $7 million decrease in costs associated with our equity NGLs reflecting a $21 million decrease related to lower volumes, partially offset by an increase of $14 million associated with 30 percent higher average natural gas prices.

•

A $7 million decrease in operating costs primarily due to lower compressor and pipeline maintenance and repair expenses at our Gulf Coast businesses associated with the absence of expenses relating to the substantial completion of a natural gas pipeline integrity management plan during 2012 as well as lower operating costs in the Four Corners area related to the consolidation of certain operations. These decreases are partially offset by higher operating and maintenance expenses and depreciation and amortization expenses associated with the Ohio Valley Midstream and Susquehanna Supply Hub businesses due to growth in these operations.

•

A $36 million favorable change in other (income) expense – net primarily attributable to the recognition of $50 million of income associated with insurance recoveries during the third quarter of 2013 related to the Geismar Incident and $3 million of insurance recoveries related to the abandonment of certain Eminence storage assets. The favorable changes are partially offset by $9 million of expense related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates as well as a $9 million accrued loss for a contingent liability associated with a pending producer claim against us recognized in third-quarter 2013.


•	A $10 million increase in other product costs primarily due to higher system management gas costs from our gas pipeline businesses (offset in segment revenues).

The decrease in segment profit includes:


•	A $76 million decrease in olefin product margins, including $59 million lower ethylene product margins primarily due to 96 percent lower volumes sold related to the loss of production as a result of the Geismar Incident.


•	A $49 million decrease in NGL margins driven primarily by lower NGL volumes, lower average NGL prices, and higher natural gas prices.


•	A $6 million decrease in marketing margins.


•	A $63 million increase in fee revenues as previously discussed.


•	A $36 million favorable change in other (income) expense – net as previously discussed.


•	A $7 million decrease in operating costs as previously discussed.

Nine months ended September 30, 2013 vs. nine months ended September 30, 2012

The decrease in segment revenues includes:

•

A $277 million decrease in revenues from our equity NGLs reflecting a decrease of $180 million due to lower volumes and a $97 million decrease associated with 13 percent lower average realized non-ethane per-unit sales prices and 49 percent lower average ethane per-unit sales prices. Equity ethane sales volumes are 78 percent lower driven by reduced ethane recoveries, as previously mentioned, and equity non-ethane volumes are 5 percent lower primarily due to a change in a customer’s contract from percent-of-liquids to fee-based processing and periods of severe winter weather conditions in the first quarter of 2013 that affected our western onshore operations that prevented producers from delivering gas.


•	A $222 million decrease in marketing revenues primarily associated with lower NGL prices and lower crude oil volumes, partially offset by higher natural gas volumes and prices. The changes in marketing revenues are more than offset by similar changes in marketing purchases.

Management’s Discussion and Analysis (Continued)

•

A $132 million decrease in olefin sales due to $169 million lower volumes, partially offset by $37 million associated with higher per-unit sales prices. Olefins production volumes are lower primarily due to the loss of production as a result of the Geismar Incident, partially offset by the absence of 7 days of unplanned turbine maintenance in April 2012, and changes in inventory management. Ethylene prices averaged 21 percent higher, partially offset by 34 percent lower butadiene prices.

•

A $142 million increase in fee revenues primarily includes $126 million higher fee revenues resulting from higher gathering volumes driven by new well connections related to infrastructure additions, a full nine months of operations, and increased gathering rates associated with customer contract modifications primarily in the Susquehanna Supply Hub, as well as contributions from the processing and fractionation facilities placed in service in the latter half of 2012 and in 2013 in the Ohio Valley Midstream business. Natural gas transportation revenues also increased $71 million from expansion projects placed into service in 2012 and 2013, as well as new rates effective in first-quarter 2013. Partially offsetting these increases is a $39 million decrease in gathering and processing revenues primarily due to a natural decline in production volumes, primarily in the Piceance basin, and severe winter weather conditions in the first quarter of 2013, which prevented producers from delivering gas in our western onshore operations. In addition, fee revenues decreased $25 million in the eastern Gulf Coast primarily driven by natural declines in Bass Lite and Blind Faith production area volumes.


•	A $54 million increase in other product sales primarily due to higher system management gas sales from our gas pipeline businesses (offset in segment costs and expenses).

The decrease in segment costs and expenses of $329 million includes:


•	A $246 million decrease in marketing purchases primarily due to lower NGL prices and lower crude oil volumes, partially offset by higher natural gas volumes and prices (substantially offset in marketing revenues).


•	A $118 million decrease in olefin feedstock purchases due to $90 million of lower volumes, primarily due to the loss of production as a result of the Geismar Incident, and $28 million lower feedstock costs, reflecting 25 percent lower average per-unit ethylene feedstock costs.


•	A $23 million decrease in costs associated with our equity NGLs reflecting a $69 million decrease due to lower natural gas volumes, partially offset by a $46 million increase related to a 37 percent increase in average natural gas prices.

•

A $54 million increase in operating costs including higher operating and maintenance expenses and depreciation and amortization expenses primarily associated with the businesses acquired in the Laser and Caiman Acquisitions in February and April 2012, respectively, and the subsequent growth in these operations. The increase in operating costs also includes $10 million of costs incurred under our insurance deductibles resulting from the Geismar Incident. These increases are partially offset by the absence of acquisition and transition costs of $22 million incurred in 2012. Additionally, compressor and pipeline maintenance and repair expenses at our Gulf Coast businesses decreased primarily due to the absence of expenses relating to the substantial completion of a natural gas pipeline integrity management plan during 2012. Operating costs in the Four Corners area also decreased related to the consolidation of certain operations.


•	A $49 million increase in other product costs primarily due to higher system management gas costs from our gas pipeline businesses (offset in segment revenues).

•

A $47 million favorable change in other (income) expense – net primarily attributable to the recognition of $50 million of income associated with insurance recoveries during the third quarter of 2013 related to the Geismar Incident and $17 million lower project development costs. The favorable changes are partially offset by a $9 million accrued loss for a contingent liability associated with a pending producer claim against us recognized in third-quarter 2013 and the absence of a $6 million gain on the sale of equipment in the second quarter of 2012.

Management’s Discussion and Analysis (Continued)

The decrease in segment profit includes:


•	A $254 million decrease in NGL margins driven primarily by lower NGL volumes and prices and higher natural gas prices.


•	A $54 million increase in operating costs as previously discussed.


•	A $14 million decrease in olefin product margins including $67 million lower ethylene volumes offset by $41 million higher ethylene prices and $25 million lower ethane costs.

•

A $3 million decrease in equity earnings primarily due to $17 million and $4 million lower equity earnings from Discovery and Aux Sable, respectively, both driven by lower NGL margins. The decreases are partially offset by $17 million higher equity earnings from Laurel Mountain driven primarily by 66 percent higher gathering volumes, the receipt of an annual minimum volume commitment fee in the second quarter of 2013, and lower leased compression expenses.


•	A $142 million increase in fee revenues as previously discussed.


•	A $47 million favorable change in other (income) expense – net as previously discussed.


•	A $24 million increase in marketing margins.

Williams NGL & Petchem Services



	Three months ended September 30,					Nine months ended September 30,
	2013			2012		2013		2012
	(Millions)
Segment revenues	$	59		$	62	$	221	$	201
Segment profit (loss)	(2		)	16		56		72

Three months ended September 30, 2013 vs. three months ended September 30, 2012

Segment revenues decreased slightly primarily due to lower sales volumes resulting from a scheduled third-quarter 2013 shutdown to conduct maintenance and to effect the ethane recovery project tie-in, substantially offset by higher average per-unit sales prices. Propylene product sales revenue decreased slightly due to 36 percent lower sales volumes substantially offset by 42 percent higher average per-unit sales prices. NGL product sales revenues remained consistent due to 6 percent lower sales volumes offset by 7 percent higher average per-unit sales prices.

Segment costs and expenses increased $15 million primarily due to $14 million higher operating and maintenance expenses resulting from scheduled third-quarter 2013 shutdown.

Segment profit (loss) decreased primarily due to $14 million higher operating and maintenance expenses resulting from scheduled third-quarter 2013 shutdown.

Nine months ended September 30, 2013 vs. nine months ended September 30, 2012

Segment revenues increased primarily due to $19 million higher NGL product sales revenues primarily due to 21 percent higher sales volumes partially offset by 6 percent lower average per-unit sales prices. The higher sales volumes resulted from the absence of the impact of filling the Boreal pipeline which occurred in June 2012 and improved production volumes in 2013, partially offset by reduced volumes due to the scheduled third-quarter 2013 shutdown.

Segment costs and expenses increased $36 million primarily due to $20 million higher operating and maintenance costs primarily resulting from the scheduled third-quarter 2013 shutdown and $13 million higher NGL feedstock costs primarily due to 21 percent higher sales volumes. Additionally, depreciation and amortization expenses increased

Management’s Discussion and Analysis (Continued)

$11 million primarily due to certain assets that were decommissioned in the third quarter of 2013 in preparation of the completion of the ethane recovery system, in addition to the depreciation related to the Boreal Pipeline, which was placed into service in June 2012. These increases were partially offset by an $8 million decrease in other expenses, primarily related to the impact of foreign currency exchange.

Segment profit decreased primarily due to $20 million higher operating and maintenance expenses resulting primarily from the scheduled third-quarter 2013 shutdown and $11 million higher depreciation and amortization expenses as previously discussed. These increased expenses were partially offset by $6 million higher NGL product margins primarily due to 21 percent higher sales volumes partially offset by 12 percent lower average per-unit margins combined with an $8 million decrease in other expenses.

Access Midstream Partners



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(Millions)
Segment profit	$	6	$	—	$	35	$	—

Three months ended September 30, 2013 vs. three months ended September 30, 2012

Segment profit in the third quarter of 2013 includes $22 million of equity earnings recognized from Access Midstream Partners, offset by $16 million noncash amortization of the difference between the cost of our investment and our underlying share of the net assets of Access Midstream Partners.

During the third-quarter 2013, we received a regular quarterly distribution of $22 million from Access Midstream Partners.

Nine months ended September 30, 2013 vs. nine months ended September 30, 2012

Segment profit in 2013 includes $57 million of equity earnings recognized from Access Midstream Partners, offset by $48 million noncash amortization of the difference between the cost of our investment and our underlying share of the net assets of Access Midstream Partners. In addition, segment profit in 2013 includes a noncash gain of $26 million resulting from Access Midstream Partners’ equity issuance in April 2013. This equity issuance resulted in the dilution of our ownership from approximately 24 percent to 23 percent, which is accounted for as though we sold a portion of our investment.

In 2013, we received regular quarterly distributions of $64 million from Access Midstream Partners.

Other



	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(Millions)
Segment revenues	$	7	$	7	$	21	$	20
Segment profit	3		1		—		61

Management’s Discussion and Analysis (Continued)

Nine months ended September 30, 2013 vs. nine months ended September 30, 2012

The unfavorable change in segment profit is primarily due to the absence of the gain of $53 million recognized in 2012 related to the 2010 sale of our interest in Accroven SRL. As part of a settlement regarding certain Venezuelan assets in the first quarter of 2012, we received payment for all outstanding balances due from this sale. (See Note 4 – Asset Sales and Other Accruals of Notes to Consolidated Financial Statements.) The unfavorable change also reflects $6 million of project development costs incurred in the first quarter of 2013.

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 and maintaining investment-grade credit metrics. Our plan for 2013 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 while maintaining a sufficient level of liquidity. In particular, we note the following for 2013:

•

We expect capital and investment expenditures to total between $4.1 billion and $4.6 billion in 2013. 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 $345 million and $405 million. Expansion capital expenditures, which are generally more discretionary to fund projects in order to grow our business are expected to total between $3.755 billion and $4.195 billion. See Company Outlook – Expansion Projects, Williams Partners and Williams NGL & Petchem Services 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 annual cash dividends of approximately $1.44 per common share in 2013, an increase of 20 percent over 2012 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 Williams and WPZ debt and/or equity securities, and utilization of our revolver and WPZ’s revolver and/or commercial paper program. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $2.11 billion and $2.15 billion in 2013.


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

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 2013. Our internal and external sources of consolidated liquidity include cash generated from our operations, cash and cash equivalents on hand, cash proceeds from WPZ’s offerings of common units, our revolver and WPZ’s revolver and/or commercial paper program. Additional sources of liquidity, if needed, include bank financings, proceeds from the issuance of debt and/or equity securities, and proceeds from asset sales. These sources are available to us at the parent level and are expected to be available to certain of our subsidiaries, particularly equity and debt issuances from WPZ. WPZ is expected to be self-funding through its cash flows from operations, use of its revolver and/or commercial paper program, and its access to capital markets. WPZ makes cash distributions to us in accordance with the partnership agreement, which considers our level of ownership and incentive distribution rights.

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:


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


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


•	Significant physical damage to facilities, especially damage to WPZ’s offshore facilities by named windstorms;


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


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



	September 30, 2013
Available Liquidity	WPZ		WMB			Total
	(Millions)
Cash and cash equivalents	$	64	$	668	(1)	$	732
Capacity available under our $1.5 billion revolver (expires July 31, 2018) (2)			1,500			1,500
Capacity available to WPZ under its $2.5 billion revolver (expires July 31, 2018) less amounts outstanding under the $2 billion commercial paper program (3) (4)	2,129					2,129
	$	2,193	$	2,168		$	4,361


(1)	Includes $342 million of cash and cash equivalents held primarily by certain international entities, that we intend to utilize to fund growth in our Canadian midstream operations and therefore, is not considered available for general corporate purposes. The remainder of our cash and cash equivalents is primarily held in government-backed instruments.


(2)	At September 30, 2013, we are in compliance with the financial covenants associated with this revolver. On July 31, 2013, we amended our $900 million revolver to increase the aggregate commitments to $1.5 billion and extend the maturity date to July 31, 2018. The amended revolver, under certain circumstances, may be increased up to an additional $500 million.

(3)

At September 30, 2013, WPZ is in compliance with the financial covenants associated with the WPZ revolver and commercial paper program. The WPZ revolver is only available to WPZ, Transco and Northwest Pipeline as co-borrowers. On July 31, 2013, WPZ amended its $2.4 billion revolver to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. The amended revolver, under certain circumstances, may be increased up to an additional $500 million.


(4)	In managing our available liquidity, we do not expect a maximum outstanding amount under WPZ’s commercial paper program in excess of the capacity available under WPZ’s revolver.

In addition to the revolvers listed above, we have issued letters of credit totaling $17 million as of September 30, 2013, under certain bilateral bank agreements.

Management’s Discussion and Analysis (Continued)

Commercial Paper

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 their own accounts as principals. As of September 30, 2013, no common units have been issued under this registration.

Equity Offerings

In August 2013, WPZ completed an equity issuance of 21,500,000 common units representing limited partner interests. Subsequently, the underwriters exercised their option to purchase 3,225,000 common units. The net proceeds of approximately $1.2 billion to WPZ were used to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes.

In March 2013, WPZ completed an equity issuance of 14,250,000 common units representing limited partner interests, including 3,000,000 common units sold to us in a private placement. Subsequently, the underwriters exercised their option to purchase 1,687,500 common units. The net proceeds of approximately $760 million to WPZ, including $143 million received from us on the private placement sale, were used to repay amounts outstanding under the WPZ revolver.

WPZ Incentive Distribution Rights

Our ownership interest in WPZ includes the right to incentive distributions determined in accordance with WPZ’s partnership agreement. We have agreed to temporarily waive our incentive distributions through 2013 related to the common units issued by WPZ to us and the seller in connection with the Caiman Acquisition. In connection with the contribution of certain Gulf olefins assets to WPZ in November 2012, we also 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. Cash distributions to us from WPZ through the November 2013 distribution have been reduced by a total of $131 million associated with these waived incentive distributions.

In May 2013, we agreed to waive additional incentive distributions of up to $200 million total through the subsequent four quarters to further support WPZ’s cash distribution metrics as its large platform of growth projects moves toward completion. The November 2013 cash distribution to us from WPZ will be reduced by $90 million in association with these waived incentive distributions.

Management’s Discussion and Analysis (Continued)

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	Positive	BBB-	N/A

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

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

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

Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A downgrade of our credit rating might increase our future cost of borrowing and would require us to post additional collateral with third parties, negatively impacting our available liquidity. As of September 30, 2013, we estimate that a downgrade to a rating below investment grade for us or WPZ could require us to post up to $7 million or $233 million, respectively, in additional collateral with third parties.

Management’s Discussion and Analysis (Continued)

Sources (Uses) of Cash



	Nine months ended September 30,
	2013			2012
	(Millions)
Net cash provided (used) by:
Operating activities	$	1,702		$	1,289
Financing activities	1,094			2,498
Investing activities	(2,903		)	(3,680		)
Increase (decrease) in cash and cash equivalents	$	(107	)	$	107

Operating activities

The factors that determine operating activities are largely the same as those that affect net income (loss), with the exception of non-cash expenses such as depreciation and amortization, provision (benefit) for deferred income taxes, and gain on reconsolidation of Wilpro entities. The increase in net cash provided by operating activities is primarily due to proceeds from insurance recoveries on the Eminence Storage Field leak and Geismar Incident, $64 million of distributions from our investment in Access Midstream Partners acquired in December 2012, and net favorable changes in operating working capital.

Financing activities

Significant transactions include:


•	$370 million net proceeds received in 2013 from WPZ’s commercial paper issuances;


•	$1.705 billion in 2013 and $960 million in 2012 received from WPZ’s revolver borrowings;


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


•	$395 million net proceeds received from Transco’s July 2012 issuance of $400 million of senior unsecured notes due 2042;


•	$2.080 billion in 2013 and $960 million in 2012 paid on WPZ’s revolver borrowings;


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


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


•	$1.819 billion in 2013 and $1.559 billion in 2012 received from WPZ’s equity offerings;


•	$722 million in 2013 and $538 million in 2012 paid for quarterly dividends on common stock;


•	$344 million in 2013 and $284 million in 2012 paid for dividends and distributions to noncontrolling interests;


•	$327 million received in contributions from noncontrolling interests in 2013.

Management’s Discussion and Analysis (Continued)

Investing activities

Significant transactions include:


•	Capital expenditures of $2.542 billion in 2013 and $1.652 billion in 2012;


•	Purchases of and contributions to our equity method investments of $350 million in 2013 and $282 million in 2012;


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


•	$325 million paid, net of cash acquired in the transaction, for WPZ’s Laser Acquisition in 2012;


•	$121 million received from the reconsolidation of the Wilpro entities in 2012. (See Note 3 – Discontinued Operations of our Notes to Consolidated Financial Statements.) This cash is only considered available for use in our international operations.

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

We have various other guarantees and commitments which are disclosed in Note 11 – Fair Value Measurements and Note 12 – 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.

Item 3

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first nine months of 2013.

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 $1.046 billion and $899 million at September 30, 2013 and December 31, 2012, 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 $209 million at September 30, 2013.

Item 4

Controls and Procedures

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

Evaluation of Disclosure Controls and Procedures

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

Third-Quarter 2013 Changes in Internal Controls

There have been no changes during the third quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our Internal Controls.

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.

The New Mexico Environment Department’s Air Quality Bureau (NMED) issued a Notice of Violation to Williams Four Corners LLC (Four Corners) on October 23, 2012, as revised on February 7, 2013, for the El Cedro Gas Treating

Plant related to the plant’s use of a standby generator and the timing of periodic testing. Settlement negotiations with the NMED to resolve the alleged violations are ongoing, with the NMED offering on April 5, 2013, to settle for $162,711.

On January 18, 2013, the NMED issued a Notice of Violation to Four Corners relating to permitting issues for condensate storage tanks at the La Jara Compressor Station. Four Corners has been in discussions with the NMED about such permitting issues since early 2011. The NMED withdrew the Notice of Violation on September 9, 2013.

On February 12, 2013, the NMED issued a Notice of Violation to Four Corners related to the alleged modification of turbine units and a separator tank and alleged failure to conduct performance tests on certain facilities at the La Jara Compressor Station. Four Corners has been in discussions with the NMED since 2012 regarding the separator tank and other permitting issues. Settlement negotiations to resolve the issues are ongoing, with the NMED offering on June 10, 2013, to settle for $1,336,564.

Other

The additional information called for by this item is provided in Note 12 – 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.

Item 1A. Risk Factors

Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2012, includes certain risk factors that could materially affect our business, financial condition or future results. Those Risk Factors have not materially changed, except as set forth below:

The time required to return WPZ’s Geismar olefins plant to operation following the explosion and fire at the facility on June 13, 2013 and the extent and timing of costs and insurance recoveries related to the incident could be materially different than we anticipate and could cause our financial results and levels of dividends to be materially different than we project.

Our projections of financial results and expected levels of dividends are based on numerous assumptions and estimates, including but not limited to the time required to return WPZ’s Geismar, Louisiana olefins plant to operation and complete the expansion project at the facility following the explosion and fire at the plant on June 13, 2013 and the extent and timing of costs and insurance recoveries related to the incident. Our financial results and levels of dividends could be materially different than we project if our assumptions and estimates related to the incident are materially different than actual outcomes.

Item 6. Exhibits



Exhibit No.		Description

Exhibit 3.1	—	Restated Certificate of Incorporation (filed on May 26, 2010, as Exhibit 3.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

Exhibit 3.2	—	Restated By-Laws (filed on May 26, 2010, as Exhibit 3.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

Exhibit 10.1	—	First Amended & Restated Credit Agreement, dated as of July 31, 2013, by and among The Williams Companies, Inc., as Borrower, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31, 2013 as Exhibit 10.1 to the Company’s quarterly report on Form 10-Q and incorporated herein by reference).

Exhibit 10.2	—	First Amended & Restated Credit Agreement, dated as of July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline LLC and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31, 2013 as Exhibit 10 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599) and incorporated herein by reference).

*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.

SIGNATURE

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



	THE WILLIAMS COMPANIES, INC.
	(Registrant)

	/s/ TED T. TIMMERMANS
	Ted T. Timmermans
	Vice President, Controller and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)

October 31, 2013

EXHIBIT INDEX



Exhibit No.		Description

Exhibit 3.1	—	Restated Certificate of Incorporation (filed on May 26, 2010, as Exhibit 3.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

Exhibit 3.2	—	Restated By-Laws (filed on May 26, 2010, as Exhibit 3.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).

Exhibit 10.1	—	First Amended & Restated Credit Agreement, dated as of July 31, 2013, by and among The Williams Companies, Inc., as Borrower, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31, 2013 as Exhibit 10.1 to the Company's quarterly report on Form 10-Q and incorporated herein by reference).

Exhibit 10.2	—	First Amended & Restated Credit Agreement, dated as of July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline LLC and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31, 2013 as Exhibit 10 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599) and incorporated herein by reference).

*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.