UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2013
	OR
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from                      to

Commission file number 1-4174

The Williams Companies, Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware	73-0569878
(State or Other Jurisdiction of Incorporation or Organization)	(IRS Employer Identification No.)
One Williams Center, Tulsa, Oklahoma	74172
(Address of Principal Executive Offices)	(Zip Code)

918-573-2000

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, $1.00 par value	New York Stock Exchange
Preferred Stock Purchase Rights	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

5.50% Junior Subordinated Convertible Debentures due 2033

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes þ    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  þ

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).    Yes  þ    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

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

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

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of the last business day of the registrant’s most recently completed second quarter was approximately $22,144,393,171.

The number of shares outstanding of the registrant’s common stock outstanding at February 21, 2014 was 684,417,475.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s Definitive Proxy Statement for the Registrant’s Annual Meeting of Stockholders to be held on May 22, 2014, are incorporated into Part III, as specifically set forth in Part III.

THE WILLIAMS COMPANIES, INC.

FORM 10-K

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	4
	Website Access to Reports and Other Information	4
	General	4
	Dividends	4
	Financial Information About Segments	4
	Business Segments	5
	Williams Partners	5
	Williams NGL & Petchem Services	12
	Access Midstream Partners	13
	Additional Business Segment Information	14
	Regulatory Matters	15
	Environmental Matters	17
	Competition	18
	Employees	19
	Financial Information about Geographic Areas	19
Item 1A.	Risk Factors	20
Item 1B.	Unresolved Staff Comments	33
Item 2.	Properties	34
Item 3.	Legal Proceedings	34
Item 4.	Mine Safety Disclosures	34
	Executive Officers of the Registrant	35
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	39
Item 6.	Selected Financial Data	40
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	75
Item 8.	Financial Statements and Supplementary Data	77
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	148
Item 9A.	Controls and Procedures	148
Item 9B.	Other Information	151
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	151
Item 11.	Executive Compensation	151
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	151
Item 13.	Certain Relationships and Related Transactions, and Director Independence	152
Item 14.	Principal Accountant Fees and Services	152
PART IV
Item 15.	Exhibits and Financial Statement Schedules	153

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DEFINITIONS

The following is a listing of certain abbreviations, acronyms and other industry terminology used throughout this Annual Report.

Measurements:

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

BPD: Barrels per day

Bcf : One billion cubic feet of natural gas

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

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

Fahrenheit

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

Mbbls/d: One thousand barrels per day

Mdth/d: One thousand dekatherms per day

MMcf/d: One million cubic feet per day

MMdth: One million dekatherms or approximately one trillion British thermal units

MMdth/d: One million dekatherms per day

TBtu: One trillion British thermal units

Consolidated Entities:

Bluegrass Pipeline: Bluegrass Pipeline Company LLC

Constitution: Constitution Pipeline Company, LLC

Gulfstar One: Gulfstar One LLC

Northwest Pipeline: Northwest Pipeline LLC

Transco: Transcontinental Gas Pipe Line Company, LLC

WPZ: Williams Partners L.P.

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

for as an equity investment, including principally the following:

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

Access Midstream Partners: Access GP and ACMP

Accroven: Accroven SRL

ACMP: Access Midstream Partners, L.P.

Aux Sable: Aux Sable Liquid Products LP

Caiman II: Caiman Energy II, LLC

Discovery: Discovery Producer Services LLC

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

Laurel Mountain: Laurel Mountain Midstream, LLC

OPPL: Overland Pass Pipeline Company LLC

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Government and Regulatory:

Code, the: Internal Revenue Code of 1986

EPA: Environmental Protection Agency

Exchange Act, the: Securities and Exchange Act of 1934, as amended

FERC: Federal Energy Regulatory Commission

IRS: Internal Revenue Service

SEC: Securities and Exchange Commission

Other:

B/B Splitter: Butylene/Butane splitter

Caiman Acquisition: WPZ’s April 2012 purchase of 100 percent of Caiman Eastern Midstream, LLC located in

the Ohio River Valley area of the Marcellus Shale region

DAC: Debutanized aromatic concentrate

Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products,

such as ethane, propane, and butane

IDR: Incentive distribution right

Laser Acquisition: WPZ’s February 2012 purchase from Delphi Midstream Partners, LLC of 100 percent of

certain entities that operate in Susquehanna County, PA and southern New York

LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures

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

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

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

Throughput:The volume of product transported or passing through a pipeline, plant, terminal, or other facility

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PART I

Item 1.Business

In this report, Williams (which includes The Williams Companies, Inc. and, unless the context otherwise indicates, all of our subsidiaries) is at times referred to in the first person as “we,” “us” or “our.” We also sometimes refer to Williams as the “Company.”

WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION

We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents electronically with the SEC under the Exchange Act. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SEC’s Internet website at www.sec.gov.

Our Internet website is www.williams.com. We make available free of charge through the Investor tab of our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Code of Ethics for Senior Officers, Board committee charters and the Williams Code of Business Conduct are also available on our Internet website. We will also provide, free of charge, a copy of any of our corporate documents listed above upon written request to our Corporate Secretary, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.

GENERAL

We are primarily an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas, 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.

Our interstate gas pipelines, domestic midstream, and domestic olefins production interests are largely held through our significant investment in Williams Partners L.P. (WPZ), one of the largest energy master limited partnerships. As of December 31, 2013, we own the general partner interest and a 62 percent limited-partner interest in WPZ. We also own a Canadian midstream business, which processes oil sands and offgas and produces olefins for petrochemical feedstocks, as well as a significant equity investment in Access Midstream Partners, which owns midstream assets in major unconventional producing areas.

We were founded in 1908, originally incorporated under the laws of the state of Nevada in 1949 and reincorporated under the laws of the state of Delaware in 1987. Williams’ headquarters are located in Tulsa, Oklahoma, with other major offices in Salt Lake City, Houston, the Four Corners Area, and Pennsylvania. Our telephone number is 918-573-2000.

DIVIDENDS

We increased our quarterly dividends from $0.325 per share in the fourth quarter of 2012 to $0.38 per share in the fourth quarter of 2013. Our Board of Directors has approved a dividend of $0.40250 per share for the first quarter of 2014.

FINANCIAL INFORMATION ABOUT SEGMENTS

See “Item 8 — Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — Note 18 – Segment Disclosures” for information with respect to each segment’s revenues, profits or losses and total assets.

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BUSINESS SEGMENTS

Substantially all our operations are conducted through our subsidiaries. Our activities in 2013 were primarily operated through the following business segments:

• Williams Partners — comprised of our master limited partnership WPZ, which includes gas pipeline and domestic midstream businesses. The gas pipeline business includes interstate natural gas pipelines and pipeline joint project investments, and the midstream business provides natural gas gathering, treating and processing services; NGL production, fractionation, storage, marketing and transportation; deepwater production handling and crude oil transportation services; an olefin production business and is comprised of several wholly owned and partially owned subsidiaries and joint project investments.

• Williams NGL & Petchem Services — primarily comprised of our Canadian midstream operations and certain domestic olefins pipeline assets. Our Canadian assets include an oil sands offgas processing plant near Fort McMurray, Alberta, an NGL/olefin fractionation facility and B/B splitter facility at Redwater, Alberta, the Boreal Pipeline, certain Canadian growth projects including a propane dehydrogenation facility, and the 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 — comprised of an indirect equity interest in Access GP and limited partner interests in ACMP, which we purchased in the fourth quarter of 2012. ACMP is a publicly traded master limited partnership that provides gathering, processing, treating and compression services to Chesapeake Energy Corporation and other producers under long-term, fee-based contracts. Access GP is the general partner of ACMP. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets of Notes to Consolidated Financial Statements.)

• Other — primarily comprised of corporate operations.

This report is organized to reflect this structure. Detailed discussion of each of our business segments follows. For a discussion of our ongoing expansion projects, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Williams Partners

Gas Pipeline Business

Williams Partners' gas pipeline businesses consist primarily of Transco and Northwest Pipeline. Our gas pipeline business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent interest in Gulfstream and a 41 percent interest in Constitution. Transco and Northwest Pipeline own and operate a combined total of approximately 13,600 miles of pipelines with a total annual throughput of approximately 3,870 TBtu of natural gas and peak-day delivery capacity of approximately 14 MMdth of natural gas.

Transco

Transco is an interstate natural gas transmission company that owns and operates a 9,700-mile natural gas pipeline system extending from Texas, Louisiana, Mississippi and the offshore Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and 12 southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, Washington, D.C., Maryland, New York, New Jersey, and Pennsylvania.

Pipeline system and customers

At December 31, 2013, Transco’s system had a mainline delivery capacity of approximately 5.9 MMdth of natural gas per day from its production areas to its primary markets, including delivery capacity from the mainline to locations on its Mobile Bay Lateral. Using its Leidy Line along with market-area storage and transportation capacity, Transco can deliver an additional 4.3 MMdth of natural gas per day for a system-wide delivery capacity

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total of approximately 10.2 MMdth of natural gas per day. Transco’s system includes 45 compressor stations, four underground storage fields, and an LNG storage facility. Compression facilities at sea level-rated capacity total approximately 1.7 million horsepower.

Transco’s major natural gas transportation customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on Transco’s system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Transco’s firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Transco’s business. Additionally, Transco offers interruptible transportation services under shorter-term agreements.

Transco has natural gas storage capacity in four underground storage fields located on or near its pipeline system or market areas and operates two of these storage fields. Transco also has storage capacity in an LNG storage facility that we own and operate. The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 200 Bcf of natural gas. At December 31, 2013, our customers had stored in our facilities approximately 143 Bcf of natural gas. In addition, wholly owned subsidiaries of Transco operate and hold a 35 percent ownership interest in Pine Needle LNG Company, LLC, an LNG storage facility with 4 Bcf of storage capacity. Storage capacity permits Transco’s customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.

Northwest Pipeline

Northwest Pipeline is an interstate natural gas transmission company that owns and operates a natural gas pipeline system extending from the San Juan basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon, and Washington to a point on the Canadian border near Sumas, Washington. Northwest Pipeline provides services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California, and Arizona directly or indirectly through interconnections with other pipelines.

Pipeline system and customers

At December 31, 2013, Northwest Pipeline’s system, having long-term firm transportation and storage redelivery agreements of approximately 3.9 MMdth/d, was composed of approximately 3,900 miles of mainline and lateral transmission pipelines and 41 transmission compressor stations having a combined sea level-rated capacity of approximately 472,000 horsepower.

Northwest Pipeline transports and stores natural gas for a broad mix of customers, including local natural gas distribution companies, municipal utilities, direct industrial users, electric power generators and natural gas marketers and producers. Northwest Pipeline’s firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of Northwest Pipeline’s business. Additionally, Northwest Pipeline offers interruptible and short-term firm transportation service.

Northwest Pipeline owns a one-third interest in the Jackson Prairie underground storage facility in Washington and contracts with a third party for storage service in the Clay basin underground field in Utah. Northwest Pipeline also owns and operates an LNG storage facility in Washington. These storage facilities have an aggregate working gas storage capacity of 14.2 MMdth of natural gas, which is substantially utilized for third-party natural gas. These natural gas storage facilities enable Northwest Pipeline to balance daily receipts and deliveries and provide storage services to certain customers.

Gulfstream

Gulfstream is an interstate natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida. Williams Partners owns, through a subsidiary, a 50 percent interest in Gulfstream. Spectra Energy Corporation, through its subsidiary, Spectra Energy Partners, LP, owns the other 50 percent interest. Williams Partners shares operating responsibilities for Gulfstream with Spectra Energy Corporation.

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Midstream Business

Williams Partners’ midstream business, one of the nation’s largest natural gas gatherers and processors, has primary service areas concentrated in major producing basins in Colorado, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio. The primary businesses are: (1) natural gas gathering, treating, and processing; (2) NGL fractionation, storage and transportation; (3) oil transportation; and (4) olefins production. These fall within the middle of the process of taking raw natural gas and crude oil from the producing fields to the consumer.

Key variables for this business will continue to be:

• Retaining and attracting customers by continuing to provide reliable services;

• Revenue growth associated with additional infrastructure either completed or currently under construction;

• Disciplined growth in core service areas and new step-out areas;

• Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;

• Prices impacting commodity-based activities.

Gathering, Processing, and Treating

Williams Partners’ gathering systems receive natural gas from producers’ oil and natural gas wells and gather these volumes to gas processing, treating or redelivery facilities. Typically, natural gas, in its raw form, is not acceptable for transportation in major interstate natural gas pipelines or for commercial use as a fuel. Williams Partners’ treating facilities remove water vapor, carbon dioxide, and other contaminants and collect condensate, but do not extract NGLs. Williams Partners’ is generally paid a fee based on the volume of natural gas gathered and/or treated, generally measured in the Btu heating value.

In addition, natural gas contains various amounts of NGLs, which generally have a higher value when separated from the natural gas stream. Our processing plants extract the NGLs in addition to removing water vapor, carbon dioxide, and other contaminants. NGL products include:

• Ethane, primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic building blocks for plastics;

• Propane, used for heating, fuel and as a petrochemical feedstock in the production of ethylene and propylene, another building block for petrochemical-based products such as carpets, packing materials, and molded plastic parts;

• Normal butane, isobutane and natural gasoline, primarily used by the refining industry as blending stocks for motor gasoline or as a petrochemical feedstock.

Our gas processing services generate revenues primarily from the following three types of contracts:

• Fee-based: We are paid a fee based on the volume of natural gas processed, generally measured in the Btu heating value. Our customers are entitled to the NGLs produced in connection with this type of processing agreement. Beginning in 2013, a portion of our fee-based processing revenues includes a share of the margins on the NGLs produced. For the year ended December 31, 2013, 72 percent of the NGL production volumes were under fee-based contracts.

• Keep-whole: Under keep-whole contracts, we (1) process natural gas produced by customers, (2) retain some or all of the extracted NGLs as compensation for our services, (3) replace the Btu content of the retained NGLs that were extracted during processing with natural gas purchases, also known as shrink replacement gas, and (4) deliver an equivalent Btu content of natural gas for customers at the plant outlet. NGLs we retain in

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connection with this type of processing agreement are referred to as our equity NGL production. Under these agreements, we have commodity price exposure on the difference between NGL and natural gas prices. For the year ended December 31, 2013, 26 percent of the NGL production volumes were under keep-whole contracts.

• Percent-of-Liquids: Under percent-of-liquids processing contracts, we (1) process natural gas produced by customers, (2) deliver to customers an agreed-upon percentage of the extracted NGLs, (3) retain a portion of the extracted NGLs as compensation for our services, and (4) deliver natural gas to customers at the plant outlet. Under this type of contract, we are not required to replace the Btu content of the retained NGLs that were extracted during processing, and are therefore only exposed to NGL price movements. NGLs we retain in connection with this type of processing agreement are also referred to as our equity NGL production. For the year ended December 31, 2013, 2 percent of the NGL production volumes were under percent-of-liquids contracts.

Our gathering and processing agreements have terms ranging from month-to-month to the life of the producing lease. Generally, our gathering and processing agreements are long-term agreements.

Demand for gas gathering and processing services is dependent on producers’ drilling activities, which is impacted by the strength of the economy, natural gas prices, and the resulting demand for natural gas by manufacturing and industrial companies and consumers. Williams Partners’ gas gathering and processing customers are generally natural gas producers who have proved and/or producing natural gas fields in the areas surrounding its infrastructure. During 2013, Williams Partners’ facilities gathered and processed gas for approximately 220 customers. Williams Partners’ top five gathering and processing customers accounted for approximately 50 percent of our gathering and processing revenue.

Demand for our equity NGLs is affected by economic conditions and the resulting demand from industries using these commodities to produce petrochemical-based products such as plastics, carpets, packing materials and blending stocks for motor gasoline and the demand from consumers using these commodities for heating and fuel. NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks.

Geographically, the midstream natural gas assets are positioned to maximize commercial and operational synergies with our other assets. For example, most of the offshore gathering and processing assets attach and process or condition natural gas supplies delivered to the Transco pipeline. Our San Juan basin, southwest Wyoming, and Piceance systems are capable of delivering residue gas volumes into Northwest Pipeline’s interstate system in addition to third-party interstate systems. Our gathering system in Pennsylvania delivers residue gas volumes into Transco’s pipeline in addition to third-party interstate systems.

Williams Partners owns and operates gas gathering, processing and treating assets within the states of Wyoming, Colorado, New Mexico, Pennsylvania, West Virginia, New York, and Ohio. We also own and operate gas gathering and processing assets and pipelines primarily within the onshore, offshore shelf, and deepwater areas in and around the Gulf Coast states of Texas, Louisiana, Mississippi, and Alabama.

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The following table summarizes our significant operated natural gas gathering assets as of December 31, 2013:

	Natural Gas Gathering Assets
	Location	Pipeline Miles	Inlet Capacity (Bcf/d)	Ownership Interest	Supply Basins
West
Rocky Mountain	Wyoming	3,587	1.1	100%	Wamsutter & SW Wyoming
Four Corners	Colorado & New Mexico	3,841	1.8	100%	San Juan
Piceance	Colorado	328	1.4	(2)	Piceance
Northeast
Ohio Valley	West Virginia	174	0.8	100%	Appalachian
Susquehanna Supply Hub	Pennsylvania & New York	277	2.3	100%	Appalachian
Laurel Mountain (1)	Pennsylvania	2,044	0.7	51%	Appalachian
Atlantic-Gulf
Canyon Chief & Blind Faith	Deepwater Gulf of Mexico	139	0.5	100%	Eastern Gulf of Mexico
Seahawk	Deepwater Gulf of Mexico	115	0.4	100%	Western Gulf of Mexico
Perdido Norte	Deepwater Gulf of Mexico	105	0.3	100%	Western Gulf of Mexico
Offshore shelf & other	Gulf of Mexico	46	0.2	100%	Eastern Gulf of Mexico
Offshore shelf & other	Gulf of Mexico	208	1.1	100%	Western Gulf of Mexico
Discovery (1)	Gulf of Mexico	358	0.6	60%	Central Gulf of Mexico

_______________

(1) Statistics reflect 100 percent of the assets from the jointly owned investments that we operate; however, our financial statements report equity method income from these investments based on our equity ownership percentage.

(2) We own 60 percent of a gathering system in the Ryan Gulch area, which we operate, with 140 miles of pipeline and 200 MMcf/d of inlet capacity. We own and operate 100 percent of the balance of the Piceance gathering system.

In addition, we own and operate several natural gas treating facilities in New Mexico, Colorado, Texas, and Louisiana which bring natural gas to specifications allowable by major interstate pipelines. At our Milagro treating facility, we also use gas-driven turbines that have the capacity to produce 60 mega-watts per day of electricity which we primarily sell into the local electrical grid.

The following table summarizes our significant operated natural gas processing facilities as of December 31, 2013:

	Natural Gas Processing Facilities
	Location	Inlet Capacity (Bcf/d)	NGL Production Capacity (Mbbls/d)	Ownership Interest	Supply Basins
West
Opal	Opal, WY	1.5	70	100%	SW Wyoming
Echo Springs	Echo Springs, WY	0.7	58	100%	Wamsutter
Ignacio	Ignacio, CO	0.5	23	100%	San Juan
Kutz	Bloomfield, NM	0.2	12	100%	San Juan
Willow Creek	Rio Blanco County, CO	0.5	30	100%	Piceance
Parachute	Garfield County, CO	1.3	7	100%	Piceance
Northeast
Fort Beeler	Marshall County, WV	0.5	62	100%	Appalachian
Atlantic-Gulf
Markham	Markham, TX	0.5	45	100%	Western Gulf of Mexico
Mobile Bay	Coden, AL	0.7	30	100%	Eastern Gulf of Mexico
Discovery (1)	Larose, LA	0.6	32	60%	Central Gulf of Mexico

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__________

(1) Statistics reflect 100 percent of the assets from the jointly owned investment that we operate; however, our financial statements report equity method income from this investment based on our equity ownership percentage.

Crude Oil Transportation and Production Handling Assets

In addition to our natural gas assets, we own and operate four deepwater crude oil pipelines and own production platforms serving the deepwater in the Gulf of Mexico. Our crude oil transportation revenues are typically volumetric-based fee arrangements. However, a portion of our marketing revenues are recognized from purchase and sale arrangements whereby the oil that we transport is purchased and sold as a function of the same index-based price. Our offshore floating production platforms provide centralized services to deepwater producers such as compression, separation, production handling, water removal, and pipeline landings. Revenue sources have historically included a combination of fixed-fee, volumetric-based fee and cost reimbursement arrangements. Fixed fees associated with the resident production at our Devils Tower facility are recognized on a units-of-production basis.

The following tables summarize our significant crude oil transportation pipelines and production handling platforms as of December 31, 2013:

	Crude Oil Pipelines
	Pipeline Miles	Capacity (Mbbls/d)	Ownership Interest	Supply Basins
Mountaineer & Blind Faith	155	150	100%	Eastern Gulf of Mexico
BANJO	57	90	100%	Western Gulf of Mexico
Alpine	96	85	100%	Western Gulf of Mexico
Perdido Norte	74	150	100%	Western Gulf of Mexico

	Production Handling Platforms
	Gas Inlet Capacity (MMcf/d)	Crude/NGL Handling Capacity (Mbbls/d)	Ownership Interest	Supply Basins
Devils Tower	210	60	100%	Eastern Gulf of Mexico
Discovery Grand Isle 115 (1)	150	10	60%	Central Gulf of Mexico

___________

(1) Statistics reflect 100 percent of the assets from the jointly owned investment that we operate; however, our financial statements report equity method income from this investment based on our equity ownership percentage.

Gulf Olefins

WPZ has an 83.3 percent undivided interest and operatorship of the olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter, and pipelines in the Gulf region. Our olefins business also operates an ethylene storage hub at Mont Belvieu using leased third-party underground storage caverns.

Our olefins production facility has a total production capacity of 1.35 billion pounds of ethylene and 90 million pounds of propylene per year. Our feedstocks for the cracker are ethane and propane; as a result, these assets are primarily exposed to the price spread between ethane and propane, and ethylene and propylene, respectively. Ethane and propane are available for purchase from third parties and from affiliates. We own ethane and propane pipeline systems in Louisiana that provide feedstock transportation to the Geismar plant and other third-party crackers. We also own a pipeline that has the capacity to supply 12 Mbbls/d of ethane from Discovery’s Paradis fractionator to the Geismar plant.

On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant. The incident (Geismar Incident) rendered the facility temporarily inoperable and resulted in significant human, financial, and operational effects. Repairs are underway and an expansion is planned to increase the facility’s ethylene production capacity by 600 million pounds per year. Following the repair and plant expansion, the Geismar plant is expected to be operational in June 2014. (See Management’s Discussion and Analysis of Financial Condition and Results of Operations - Overview.)

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Our refinery grade propylene splitter has a production capacity of approximately 500 million pounds per year of propylene. At our propylene splitter, we purchase refinery grade propylene and fractionate it into polymer grade propylene and propane; as a result, this asset is exposed to the price spread between those commodities.

As a merchant producer of ethylene and propylene, our product sales are to customers for use in making plastics and other downstream petrochemical products destined for both domestic and export markets.

Marketing Services

We market NGL products to a wide range of users in the energy and petrochemical industries. The NGL marketing business transports and markets our equity NGLs from the production at our processing plants, and also markets NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers, and the NGL volumes owned by Discovery. The NGL marketing business bears the risk of price changes in these NGL volumes while they are being transported to final sales delivery points. In order to meet sales contract obligations, we may purchase products in the spot market for resale. Other than a long-term agreement to sell our equity NGLs transported on OPPL to ONEOK Hydrocarbon L.P., the majority of sales are based on supply contracts of one year or less in duration. Sales to ONEOK Hydrocarbon L.P., accounted for 9 percent, 14 percent, and 17 percent of our consolidated revenues in 2013, 2012, and 2011, respectively.

In certain situations to facilitate our gas gathering and processing activities, we buy natural gas from our producer customers for resale.

We also market olefin products to a wide range of users in the energy and petrochemical industries. In order to meet sales contract obligations, we may purchase olefin products for resale.

Other NGL & Petchem Operations

We own interests in and/or operate NGL fractionation and storage assets. These assets include a 50 percent interest in an NGL fractionation facility near Conway, Kansas, with capacity of slightly more than 100 Mbbls/d and a 31.5 percent interest in another fractionation facility in Baton Rouge, Louisiana, with a capacity of 60 Mbbls/d. We also own approximately 20 million barrels of NGL storage capacity in central Kansas near Conway.

We own approximately 170 miles of pipelines in the Houston Ship Channel area which transport a variety of products including ethane, propane, ammonia, tertiary butyl alcohol, and other industrial products used in the petrochemical industry. We also own a tunnel crossing pipeline under the Houston Ship Channel which contains multiple pipelines which are leased to third parties.

We also own a 14.6 percent equity interest in Aux Sable and its Channahon, Illinois, gas processing and NGL fractionation facility near Chicago. The facility is capable of processing up to 2.1 Bcf/d of natural gas from the Alliance Pipeline system and fractionating approximately 102 Mbbls/d of extracted liquids into NGL products. Additionally, Aux Sable owns an 80 MMcf/d gas conditioning plant and a 12-inch, 83-mile gas pipeline infrastructure in North Dakota that provides additional NGLs to Channahon from the Bakken Shale in the Williston basin.

WPZ Operating Areas

WPZ organizes these businesses into the following operating areas:

Northeast G&P is comprised of the midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 51 percent equity investment in Laurel Mountain and a 47.5 percent equity investment in Caiman II.

Atlantic-Gulf is comprised of Transco and significant natural gas gathering and processing and crude production handling and transportation in the Gulf Coast region, as well as a 50 percent equity investment in Gulfstream, a 41 percent interest in Constitution (a consolidated entity), and a 60 percent equity investment in Discovery.

West is comprised of the gathering, processing and treating operations in New Mexico, Colorado, and Wyoming and Northwest Pipeline.

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NGL & Petchem Services is comprised of the energy commodities marketing business, an NGL fractionator and storage facilities near Conway, Kansas, a 50 percent equity investment in OPPL, and an 83.3 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf Coast region.

Operated Equity Investments

Discovery

We own a 60 percent equity interest in and operate the facilities of Discovery. Discovery’s assets include a 600

MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 32 Mbbls/d NGL fractionator plant near Paradis, Louisiana, and an offshore natural gas gathering and transportation system in the Gulf of Mexico. Construction is in progress for the Keathley Canyon Connector, a deepwater lateral pipeline in the central deepwater Gulf of Mexico. 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.

Laurel Mountain

We own a 51 percent equity interest in a joint venture, Laurel Mountain, that includes a gathering system that we operate in western Pennsylvania. Laurel Mountain has a long-term, dedicated, volumetric-based fee agreement, with exposure to natural gas prices, to gather the anchor customer’s production in the western Pennsylvania area of the Marcellus Shale.

Overland Pass Pipeline

We also operate and own a 50 percent ownership interest in OPPL. OPPL is capable of transporting 255 Mbbls/d and includes approximately 1,096 miles of NGL pipeline extending from Opal, Wyoming, to the Mid-Continent NGL market center near Conway, Kansas, along with extensions into the Piceance and Denver-Julesberg basins in Colorado. In 2013, a pipeline connection and capacity expansions were installed to accommodate volumes coming from the Bakken Shale in the Williston basin in North Dakota. Our equity NGL volumes from our two Wyoming plants and our Willow Creek facility in Colorado are dedicated for transport on OPPL under a long-term transportation agreement.

Operating Statistics

The following table summarizes our significant operating statistics for Williams Partners’ midstream business:

	2013	2012	2011
Volumes: (1)
Gathering (Tbtu)	1,731	1,616	1,377
Plant inlet natural gas (Tbtu)	1,549	1,638	1,592
NGL production (Mbbls/d) (2)	143	209	189
NGL equity sales (Mbbls/d) (2)	40	77	77
Crude oil transportation (Mbbls/d) (2)	117	126	105
Geismar ethylene sales (millions of pounds)	467	1,058	1,038

__________

(1) Excludes volumes associated with Partially Owned Entities.

(2) Annual average Mbbls/d.

Williams NGL & Petchem Services

The Williams NGL & Petchem Services segment consists primarily of our Canadian midstream business, certain domestic olefins pipeline assets, and the proposed 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.

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Our Canadian operations that include an oil sands offgas processing plant located near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and B/B Splitter facility, both of which are located at Redwater, Alberta, which is near Edmonton, Alberta, and the Boreal Pipeline which transports NGLs and olefins from our Fort McMurray plant to our Redwater fractionation facility. We operate the Fort McMurray area processing plant and the Boreal Pipeline, while another party operates the Redwater facilities on our behalf. Our Fort McMurray area facilities extract liquids from the offgas produced by a third-party oil sands bitumen upgrader. Our arrangement with the third-party upgrader is a “keep-whole” type where we remove a mix of NGLs and olefins from the offgas and return the equivalent heating value to the third-party upgrader in the form of natural gas, as well as a profit share where a portion above a threshold is shared with the third party. We extract, fractionate, treat, store, terminal and sell the ethane/ethylene, propane, propylene, normal butane (butane), isobutane/butylene (butylene) and condensate recovered from this process. The commodity price exposure of this asset is the spread between the price for natural gas and the NGL and olefin products we produce. We continue to be the only NGL/olefins fractionator in western Canada and the only processor of oil sands upgrader offgas. Our extraction of liquids from upgrader offgas streams allows the upgraders to burn cleaner natural gas streams and reduces their overall air emissions.

The Fort McMurray extraction plant has processing capacity of 121 MMcf/d with the ability to recover in excess of 26 Mbbls/d of olefin and NGL products. Our Redwater fractionator has a liquids handling capacity of 26 Mbbls/d. The B/B Splitter, which has a production capacity of 3.7 Mbbls/d of butylene and 3.7 Mbbls/d of butane, further fractionates the butylene/butane mix produced at our Redwater fractionators into separate butylene and butane products, which receive higher values and are in greater demand. We also purchase small volumes of olefin/NGLs mixes from third-party gas processors, fractionate the olefins and NGLs at our Redwater plant and sell the resulting products. The Boreal Pipeline is a 261-mile pipeline in Canada that transports recovered NGLs and olefins from our extraction plant in Fort McMurray to our Redwater fractionation facility. The pipeline has an initial capacity of 43 Mbbls/d that can be increased to an ultimate capacity of 125 Mbbls/d with additional pump stations.Our products are sold within Canada and the United States.

In the second quarter of 2013, we formed a joint project to develop the Bluegrass Pipeline. We own a 50 percent interest in Bluegrass Pipeline (a consolidated entity). The proposed 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 in discussions with potential customers regarding commitments to the pipeline. Completion of this project is subject to all necessary or required approvals, elections, and actions, as well as execution of formal customer commitments. We currently estimate the Bluegrass Pipeline will be in-service in mid-to-late 2016.

Operating Statistics

The following table summarizes our significant operating statistics:

	2013	2012	2011
Volumes:
Canadian propylene sales (millions of pounds)	118	153	139
Canadian NGL sales (millions of gallons)	172	165	163

Access Midstream Partners

Our Access Midstream Partners segment consists of our equity investment in ACMP. This investment includes an indirect 50 percent interest in Access GP, including IDRs. In addition, we hold approximately 23 percent of ACMP’s outstanding limited partnership units. ACMP is a publicly traded master limited partnership that provides gathering, treating, and compression services to producers under long-term, fee-based contracts.

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The following table summarizes ACMP’s average daily throughput and assets by region as of and for the year ended December 31, 2013:

	Location	Average Throughput (Bcf/d) (1)	Approximate Length of Pipeline (Miles)	Gas Compression (Horsepower)
Region
Barnett Shale	Texas	1.045	859	150,945
Eagle Ford Shale	Texas	0.263	870	93,847
Haynesville Shale	Louisiana	0.669	582	20,195
Marcellus Shale	Pennsylvania & West Virginia	1.019	823	136,090
Niobrara Shale	Wyoming	0.015	132	15,665
Utica Shale	Ohio	0.107	265	63,505
Mid-Continent	Texas, Oklahoma, Kansas, & Arkansas	0.581	2,805	108,735
Total		3.699	6,336	588,982

__________

(1) Throughput in all regions represents net throughput allocated to ACMP’s Partnership interest.

Additional Business Segment Information

Our ongoing business segments are presented as continuing operations in the accompanying financial statements and Notes to Consolidated Financial Statements included in Part II.

We perform certain management, legal, financial, tax, consultation, information technology, administrative and other services for our subsidiaries.

Our principal sources of cash are from dividends, distributions and advances from our subsidiaries, investments, payments by subsidiaries for services rendered, and, if needed, external financings, and net proceeds from asset sales. The terms of certain subsidiaries’ borrowing arrangements may limit the transfer of funds to us under certain conditions.

We believe that we have adequate sources and availability of raw materials and commodities for existing and anticipated business needs. Our interstate pipeline systems are all regulated in various ways resulting in the financial return on the investments made in the systems being limited to standards permitted by the regulatory agencies. Each of the pipeline systems has ongoing capital requirements for efficiency and mandatory improvements, with expansion opportunities also necessitating periodic capital outlays.

Revenues by service that exceeded 10 percent of consolidated revenue include:

	2013		2012		2011
	(Millions)
Service:
Regulated natural gas transportation and storage	$	1,713	$	1,609	$	1,569
Gathering & processing	932		844		703

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REGULATORY MATTERS

Williams Partners

FERC

Williams Partners’ gas pipeline interstate transmission and storage activities are subject to FERC regulation under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978, and, as such, its rates and charges for the transportation of natural gas in interstate commerce, its accounting, and the extension, enlargement or abandonment of its jurisdictional facilities, among other things, are subject to regulation. Each gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. FERC Standards of Conduct govern how our interstate pipelines communicate and do business with gas marketing employees. Among other things, the Standards of Conduct require that interstate pipelines not operate their systems to preferentially benefit gas marketing functions.

FERC regulation requires all terms and conditions of service, including the rates charged, to be filed with and approved by the FERC before any changes can go into effect. Each of our interstate natural gas pipeline companies establishes its rates primarily through the FERC’s ratemaking process. Key determinants in the ratemaking process are:

• Costs of providing service, including depreciation expense;

• Allowed rate of return, including the equity component of the capital structure and related income taxes;

• Contract and volume throughput assumptions.

The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues previously collected may be subject to refund.

Williams Partners also owns interests in and operates two offshore transmission pipelines that are regulated by the FERC because they are deemed to transport gas in interstate commerce. Black Marlin Pipeline Company provides transportation service for offshore Texas production in the High Island area and redelivers that gas to intrastate pipeline interconnects near Texas City. Discovery provides transportation service for offshore Louisiana production from the South Timbalier, Grand Isle, Ewing Bank, and Green Canyon (deepwater) areas to an onshore processing facility and downstream interconnect points with major interstate pipelines. In addition, Williams Partners owns a 50 percent interest in, and is the operator of OPPL, which is an interstate natural gas liquids pipeline regulated by the FERC pursuant to the Interstate Commerce Act. OPPL provides transportation service pursuant to tariffs filed with the FERC.

Pipeline Safety

Williams Partners’ gas pipelines are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, and the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety Act), which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. The United States Department of Transportation (USDOT) administers federal pipeline safety laws.

Federal pipeline safety laws authorize USDOT to establish minimum safety standards for pipeline facilities and persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce. USDOT has also established reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, USDOT performs pipeline safety inspections and has the authority to initiate enforcement actions.

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Federal pipeline safety regulations contain an exemption that applies to gathering lines in certain rural locations. A substantial portion of our gathering lines qualify for that exemption and are currently not regulated under federal law. However, USDOT is completing a congressionally-mandated review of the adequacy of the existing federal and state regulations for gathering lines and has indicated that it may apply additional safety standards to rural gas gathering lines in the future.

States are preempted by federal law from regulating pipeline safety for interstate pipelines but most are certified by USDOT to assume responsibility for enforcing intrastate pipeline safety regulations and inspecting intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, they vary considerably in their authority and capacity to address pipeline safety.

On January 3, 2012, the Pipeline Safety Act was enacted. The Pipeline Safety Act requires USDOT to complete a number of reports in preparation for potential rulemakings. The issues addressed in these rulemaking provisions include, but are not limited to, the use of automatic or remotely controlled shut-off valves on new or replaced transmission line facilities, modifying the requirements for pipeline leak detection systems, and expanding the scope of the pipeline integrity management requirements. USDOT is considering these and other provisions in the Pipeline Safety Act and has sought public comment on changes to the standards in its pipeline safety regulations.

Pipeline Integrity Regulations

We have developed an enterprise wide Gas Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for gas transmission pipelines that could affect high consequence areas in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments to be completed within required time frames. In meeting the integrity regulations, we have identified high consequence areas and developed baseline assessment plans. We completed the assessments within the required time frames, with one exception which was reported to PHMSA. Ongoing periodic reassessments and initial assessments of any new high consequence areas are expected to be completed within the time frames required by the rule. We estimate that the cost to be incurred in 2014 associated with this program to be approximately $43 million, most of which we expect to be capital expenditures. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through Northwest Pipeline’s and Transco’s rates.

We developed a Liquid Integrity Management Plan that we believe meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires liquid pipeline operators to develop an integrity management program for liquid transmission pipelines that could affect high consequence areas (whether onshore or offshore) in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments expected to be completed within required time frames. In meeting the integrity regulations, we utilized government defined high consequence areas and developed baseline assessment plans. We completed assessments within the required time frames. We estimate that the cost to complete the remediation associated with the 2013 assessments will be approximately $100,000, most of which we expect to be included in 2014 operating expenses. Ongoing periodic reassessments and initial assessments of any new high consequence areas are expected to be completed within the time frames required by the rule. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business.

State Gathering Regulation

Our onshore midstream gathering operations are subject to regulation by states in which we operate. Of the states where our midstream business gathers gas, currently only Texas actively regulates gathering activities. Texas regulates gathering primarily through complaint mechanisms under which the state commission may resolve disputes involving an individual gathering arrangement.

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OCSLA

Our offshore midstream gathering is subject to the Outer Continental Shelf Lands Act (OCSLA). Although offshore gathering facilities are not subject to the NGA, offshore transmission pipelines are subject to the NGA, and in recent years the FERC has taken a broad view of offshore transmission, finding many shallow-water pipelines to be jurisdictional transmission. Most offshore gathering facilities are subject to the OCSLA, which provides in part that outer continental shelf pipelines “must provide open and nondiscriminatory access to both owner and nonowner shippers.”

Olefins

Williams Partners’ olefins assets are regulated by the Louisiana Department of Environmental Quality, the Texas Railroad Commission, and various other state and federal entities regarding our liquids pipelines.

These olefins assets are also subject to the liquid pipeline safety and integrity regulations previously discussed above since both Louisiana and Texas have adopted the integrity management regulations defined by PHMSA.

Williams NGL & Petchem Services

Our Canadian assets are regulated by the Alberta Energy Regulator (“AER”), which includes specifics to pipeline safety and integrity. The regulatory system for the Alberta oil and gas industry incorporates a large measure of self-regulation, providing that licensed operators are held responsible for ensuring that their operations are conducted in accordance with all provincial regulatory requirements. For situations in which noncompliance with the applicable regulations is at issue, the AER has an enforcement process with escalating consequences.

See Note 17 – Contingent Liabilities and Commitments of our Notes to Consolidated Financial Statements for further details on our regulatory matters.

ENVIRONMENTAL MATTERS

Our operations are subject to federal environmental laws and regulations as well as the state, local and tribal laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil, or water, as well as liability for cleanup costs. Materials could be released into the environment in several ways including, but not limited to:

• Leakage from gathering systems, underground gas storage caverns, pipelines, processing or treating facilities, transportation facilities and storage tanks;

• Damage to facilities resulting from accidents during normal operations;

• Damages to onshore and offshore equipment and facilities resulting from storm events or natural disasters;

• Blowouts, cratering and explosions.

In addition, we may be liable for environmental damage caused by former owners or operators of our properties.

We believe compliance with current environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings or current competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, fines and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses.

For additional information regarding the potential impact of federal, state, tribal or local regulatory measures on our business and specific environmental issues, please refer to “Risk Factors — “Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities and expenditures and could exceed current expectations,”

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and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental” and “Environmental Matters” in Note 17 – Contingent Liabilities and Commitments of our Notes to Consolidated Financial Statements.

COMPETITION

Williams Partners

For Williams Partners’ gas pipeline business, the natural gas industry has undergone significant change over the past two decades. A highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. More recently large reserves of shale gas have been discovered, in many cases much closer to major market centers. As a result, pipeline capacity is being used more efficiently and competition among pipeline suppliers to connect growing supply to market has increased.

Local distribution company (LDC) and electric industry restructuring by states have affected pipeline markets. Pipeline operators are increasingly challenged to accommodate the flexibility demanded by customers and allowed under tariffs. The state plans have in some cases discouraged LDCs from signing long-term contracts for new capacity.

States have developed new plans that require utilities to encourage energy saving measures and diversify their energy supplies to include renewable sources. This has lowered the growth of residential gas demand. However, due to relatively low prices of natural gas, demand for electric power generation has increased.

These factors have increased the risk that customers will reduce their contractual commitments for pipeline capacity from traditional producing areas. Future utilization of pipeline capacity will depend on these factors and others impacting both U.S. and global demand for natural gas.

In Williams Partners’ midstream business, we face regional competition with varying competitive factors in each basin. Our gathering and processing business competes with other midstream companies, interstate and intrastate pipelines, producers and independent gatherers and processors. We primarily compete with five to ten companies across all basins in which we provide services. Numerous factors impact any given customer’s choice of a gathering or processing services provider, including rate, location, term, reliability, timeliness of services to be provided, pressure obligations and contract structure. We also compete in recruiting and retaining skilled employees.

Ethylene and propylene markets, and therefore Williams Partners’ olefins business, compete in a worldwide marketplace. Due to our NGL feedstock position at Geismar, we expect to benefit from the lower cost position in North America versus other crude based feedstocks worldwide. The majority of North American olefins producers have significant downstream petrochemical manufacturing for plastics and other products. As such, they buy or sell ethylene and propylene as required. We operate as a merchant seller of olefins with no downstream manufacturing, and therefore can be either a supplier or a competitor at any given time to these other companies. We compete on the basis of service, price and availability of the products we produce.

Williams NGL & Petchem Services

Our Canadian midstream facilities continue to be the only NGL/olefins fractionator in western Canada and the only processor of oil sands upgrader offgas. Our extraction of liquids from the upgrader offgas stream allows the upgraders to burn cleaner natural gas streams and reduce their overall air emissions. Our Canadian midstream business competes for the sale of its products with traditional Canadian midstream companies on the basis of operational expertise, price, service offerings and availability of the products we produce.

For additional information regarding competition for our services or otherwise affecting our business, please refer to “Risk Factors - The long-term financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access and demand for those supplies in our traditional markets, “-Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results,” and “- We may not be able to replace, extend, or add

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additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay distributions, and our ability to grow.” 

EMPLOYEES

At February 1, 2014, we had approximately 4,909 full-time employees.

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

See Note 18 – Segment Disclosures of our Notes to Consolidated Financial Statements for amounts of revenues during the last three fiscal years from external customers attributable to the United States and all foreign countries. Also see Note 18 – Segment Disclosures of our Notes to Consolidated Financial Statements for information relating to long-lived assets during the last three fiscal years, located in the United States and all foreign countries.

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Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT

FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF

THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

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

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,”“in service date,” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

• Amounts and nature of future capital expenditures;

• Expansion and growth of our business and operations;

• Financial condition and liquidity;

• Business strategy;

• Cash flow from operations or results of operations;

• The levels of dividends to stockholders;

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

• Demand for our services.

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

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

• Availability of supplies, market demand, and volatility of prices;

• Inflation, interest rates, fluctuation in foreign exchange rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);

• The strength and financial resources of our competitors and the effects of competition;

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

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

• Development of alternative energy sources;

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

• Costs of, changes in, or the results of laws, government regulations (including safety and environmental regulations), environmental liabilities, litigation, and rate proceedings;

• Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;

• Changes in maintenance and construction costs;

• Changes in the current geopolitical situation;

• Our exposure to the credit risk of our customers and counterparties;

• Risks related to financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of capital;

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

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

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

• Additional risks described in our filings with the SEC.

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

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section.

RISK FACTORS

You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, operating results, and financial condition, as well as adversely affect the value of an investment in our securities.

Prices for NGLs, olefins, natural gas, oil and other commodities, are volatile and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain our existing businesses.

Our revenues, operating results, future rate of growth and the value of certain components of our businesses depend primarily upon the prices of NGLs,olefins, natural gas, oil or other commodities, and the differences between prices

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of these commodities. Price volatility can impact both the amount we receive for our products and services and the volume of products and services we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Price volatility can also have an adverse effect on our business, results of operations, financial condition and cash flows.

The markets for NGLs,olefins, natural gas, oil and other commodities are likely to continue to be volatile. Wide fluctuations in prices might result from one or more factors beyond our control, including:

• Worldwide and domestic supplies of and demand for natural gas, NGLs,olefins, oil, and related commodities;

• Turmoil in the Middle East and other producing regions;

• The activities of the Organization of Petroleum Exporting Countries;

• The level of consumer demand;

• The price and availability of other types of fuels or feedstocks;

• The availability of pipeline capacity;

• Supply disruptions, including plant outages and transportation disruptions;

• The price and quantity of foreign imports of natural gas and oil;

• Domestic and foreign governmental regulations and taxes;

• The credit of participants in the markets where products are bought and sold.

The long-term financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access, and demand for those supplies in our traditional markets.

Our ability to maintain and expand our natural gas transportation and midstream businesses depends on the level of drilling and production by third parties in our supply basins. Production from existing wells and natural gas supply basins with access to our pipeline and gathering systems will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. In addition, low prices for natural gas, regulatory limitations, or the lack of available capital could adversely affect the development and production of additional natural gas reserves, the installation of gathering, storage, and pipeline transportation facilities and the import and export of natural gas supplies. The competition for natural gas supplies to serve other markets could also reduce the amount of natural gas supply for our customers. A failure to obtain access to sufficient natural gas supplies will adversely impact our ability to maximize the capacities of our gathering, transportation and processing facilities.

Demand for our services is dependent on the demand for gas in the markets we serve. Alternative fuel sources such as electricity, coal, fuel oils or nuclear energy could reduce demand for natural gas in our markets and have an adverse effect on our business.

A failure to obtain access to sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could result in impairments of our assets and have a material adverse effect on our business, financial condition and results of operations.

We may not be able to grow or effectively manage our growth.

As part of our growth strategy, we consider acquisition opportunities and engage in significant capital projects. We recently implemented our project lifecycle process and refocused our investment evaluation process. These are processes we use to identify, evaluate and execute on acquisition opportunities and capital projects. We may not always

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have sufficient and accurate information to identify and value potential opportunities and risks or our investment evaluation process may be incomplete or flawed. Regarding potential acquisitions, suitable acquisition candidates may not be available on terms and conditions we find acceptable or, where multiple parties are trying to acquire an acquisition candidate, we may not be chosen as the acquirer. If we are able to acquire a targeted business, we may not be able to successfully integrate the acquired businesses and realize anticipated benefits in a timely manner. Our growth may also be dependent upon the construction of new natural gas gathering, transportation, compression, processing or treating pipelines and facilities, NGL transportation, fractionation or storage facilities or olefins processing facilities, as well as the expansion of existing facilities. We also face all the risks associated with construction. These risks include the inability to obtain skilled labor, equipment, materials, permits, rights-of-way and other required inputs in a timely manner such that projects are completed on time and the risk that construction cost overruns could cause total project costs to exceed budgeted costs. Additional risks associated with growing our business include, among others, that:

• Changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings and cash flow relating to potential investment targets, resulting in outcomes which are materially different than anticipated;

• We could be required to contribute additional capital to support acquired businesses or assets. We may assume liabilities that were not disclosed to us, that exceed our estimates and for which contractual protections are either unavailable or prove inadequate;

• Acquisitions could disrupt our ongoing business, distract management, divert financial and operational resources from existing operations and make it difficult to maintain our current business standards, controls and procedures;

• Acquisitions and capital projects may require substantial new capital, either by the issuance of debt or equity, and we may not be able to access capital markets or obtain acceptable terms.

If realized, any of these risks could have an adverse impact on our results of operations, including the possible impairment of our assets, and could also have an adverse impact on our financial position or cash flows.

We do not own all of the interests in the Partially Owned Entities, which could adversely affect our ability to operate and control these assets in a manner beneficial to us.

Because we do not control the Partially Owned Entities, we may have limited flexibility to control the operation of or cash distributions received from these entities. The Partially Owned Entities’ organizational documents require distribution of their available cash to their members on a quarterly basis; however, in each case, available cash is reduced, in part, by reserves appropriate for operating the businesses. At December 31, 2013, our investments in the Partially Owned Entities accounted for approximately 16 percent of our total consolidated assets. Conflicts of interest may arise in the future between us, on the one hand, and our Partially Owned Entities, on the other hand, with regard to our Partially Owned Entities’ governance, business and operations. If a conflict of interest arises between us and a Partially Owned Entity, other owners may control the Partially Owned Entity’s actions with respect to such matter (subject to certain limitations), which could be detrimental to our business. Any future disagreements with the other co-owners of these assets could adversely affect our ability to respond to changing economic or industry conditions, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Holders of our common stock may not receive dividends in the amount identified in guidance or any dividends.

We may not have sufficient cash flow each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash we dividend will depend on various factors, some of which are beyond our control, including:

• The amount of cash that WPZ, our other subsidiaries and the Partially Owned Entities distribute to us;

• The amount of cash we generate from our operations, our working capital needs, our level of capital expenditures, and our ability to borrow;

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• The restrictions contained in our indentures and credit facility and our debt service requirements;

• The cost of acquisitions, if any.

A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage and a decrease in the value of our stock price.

Our cash flow depends heavily on the earnings and distributions of WPZ.

Our partnership interest, including the general partner’s holding of incentive distribution rights, in WPZ is our largest cash-generating asset. Therefore, our cash flow is heavily dependent upon the ability of WPZ to make distributions to its partners. A significant decline in WPZ’s earnings and/or distributions would have a corresponding negative impact on us.

Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.

We have numerous competitors in all aspects of our businesses, and additional competitors may enter our markets. Some of our competitors are large oil, natural gas and petrochemical companies that have greater access to supplies of natural gas and NGLs than we do. In addition, current or potential competitors may make strategic acquisitions or have greater financial resources than we do, which could affect our ability to make strategic investments or acquisitions. Our competitors may be able to respond more quickly to new laws or regulations or emerging technologies or to devote greater resources to the construction, expansion or refurbishment of their facilities than we can. Similarly, a highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. Failure to successfully compete against current and future competitors could have a material adverse effect on our business, results of operations, financial condition and cash flows.

We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay dividends, and our ability to grow.

We rely on a limited number of customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. Although many of our customers and suppliers are subject to long-term contracts, if we are unable to replace or extend such contracts or add additional customers, each on favorable terms, if at all, our financial condition, growth plans, and the amount of cash available to pay distributions could be adversely affected. Our ability to replace, extend, or add additional customer or supplier contracts on favorable terms, or at all, is subject to a number of factors, some of which are beyond our control, including:

• The level of existing and new competition in our businesses or from alternative fuel sources, such as electricity, coal, fuel oils, or nuclear energy;

• Natural gas, NGL, and olefins prices, demand, availability and margins in our markets. Higher prices for energy commodities related to our businesses could result in a decline in the demand for those commodities and, therefore, in customer contracts or throughput on our pipeline systems. Also, lower energy commodity prices could result in a decline in the production of energy commodities resulting in reduced customer contracts, supply contracts, and throughput on our pipeline systems;

• General economic, financial markets and industry conditions;

• The effects of regulation on us, our customers and our contracting practices;

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• Our ability to understand our customers’ expectations, efficiently and reliably deliver high quality services and effectively manage customer relationships. The results of these efforts will impact our reputation and positioning in the market.

Our operations are subject to operational hazards and unforeseen interruptions.

There are operational risks associated with the gathering, transporting, storage, processing and treating of natural gas, the fractionation, transportation and storage of NGLs, processing of olefins, and crude oil transportation and production handling, including:

• Aging infrastructure and mechanical problems;

• Damages to pipelines and pipeline blockages or other pipeline interruptions;

• Uncontrolled releases of natural gas (including sour gas), NGLs, brine or industrial chemicals;

• Collapse or failure of storage caverns;

• Operator error;

• Damage caused by third-party activity, such as operation of construction equipment;

• Pollution and other environmental risks;

• Fires, explosions, craterings and blowouts;

• Truck and rail loading and unloading;

• Operating in a marine environment.

Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, loss of services to our customers, reputational damage and substantial losses to us. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. An event such as those described above could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.

We do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.

In accordance with customary industry practice, we maintain insurance against some, but not all, risks and losses, and only at levels we believe to be appropriate. We currently maintain excess liability insurance with limits of $610 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers us, our subsidiaries, and certain of our affiliates for legal and contractual liabilities arising out of bodily injury or property damage, including resulting loss of use to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and NGL operations.

Although we maintain property insurance on certain physical assets that we own, lease or are responsible to insure, the policy may not cover the full replacement cost of all damaged assets or the entire amount of business interruption loss we may experience. In addition, certain perils may be excluded from coverage or be sub-limited. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. We may elect to self insure a portion of our risks. We do not insure our onshore underground pipelines for physical damage, except at certain locations such as river crossings and compressor stations. Offshore assets are covered for property damage when loss

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is due to a named windstorm event, but coverage for loss caused by a named windstorm is significantly sub-limited and subject to a large deductible. All of our insurance is subject to deductibles.

In addition, to the insurance coverage described above, we are a member of Oil Insurance Limited (OIL), an energy industry mutual insurance company, which provides coverage for damage to our property. As an insured member of OIL, we share in the losses among other OIL members even if our property is not damaged.

The occurrence of any risks not fully covered by insurance could have a material adverse effect on our business, results of operations, financial condition, cash flows and our ability to repay our debt.

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.

Our assets and operations, as well as our customers’ assets and operations, can be adversely affected by weather and other natural phenomena.

Our assets and operations, especially those located offshore, and our customers’ assets and operations can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes, fires and other natural phenomena and weather conditions, including extreme or unseasonable temperatures, making it more difficult for us to realize the historic rates of return associated with our assets and operations. A significant disruption in our or our customers’ operations or a significant liability for which we are not fully insured could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Acts of terrorism could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Given the volatile nature of the commodities we transport, process, store and sell, our assets and the assets of our customers and others in our industry may be targets of terrorist activities. A terrorist attack could create significant price volatility, disrupt our business, limit our access to capital markets or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport or distribute natural gas, NGLs or other commodities. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.

We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. While we believe that we maintain appropriate information security policies, practices and protocols, we face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational industrial control systems and safety systems that operate our pipelines, plants and assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists,” or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. We

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could also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information.

Breaches in our information technology infrastructure or physical facilities, or other disruptions including those arising from theft, vandalism, fraud or unethical conduct, could result in damage to our assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.

The natural gas sales, transportation and storage operations of our gas pipelines are subject to regulation by the FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines, including a reasonable rate of return.

In addition to regulation by other federal, state and local regulatory authorities, under the Natural Gas Act of 1938, interstate pipeline transportation and storage service is subject to regulation by the FERC. Federal regulation extends to such matters as:

• Transportation and sale for resale of natural gas in interstate commerce;

• Rates, operating terms, types of services and conditions of service;

• Certification and construction of new interstate pipelines and storage facilities;

• Acquisition, extension, disposition or abandonment of existing interstate pipelines and storage facilities;

• Accounts and records;

• Depreciation and amortization policies;

• Relationships with affiliated companies who are involved in marketing functions of the natural gas business;

• Market manipulation in connection with interstate sales, purchases or transportation of natural gas.

Regulatory or administrative actions in these areas, including successful complaints or protests against rates of the gas pipelines, can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs and otherwise altering the profitability of our pipeline business.

Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities and expenditures that could exceed expectations.

Our operations are subject to extensive federal, state, tribal and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment and the security of chemical and industrial facilities. Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, storage, processing and treating of natural gas, fractionation, transportation and storage of NGLs, processing of olefins, and crude oil transportation and production handling as well as waste disposal practices. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations and delays in granting permits.

Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil and wastes on, under or from our properties and facilities. Private parties, including the owners of properties through which our pipeline and gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages

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for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours.

We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.

In addition, climate change regulations and the costs associated with the regulation of emissions of greenhouse gases (GHGs) have the potential to affect our business. Regulatory actions by the EPA or the passage of new climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage our GHG compliance program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Climate change and GHG regulation could also reduce demand for our services.

If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues could be adversely affected.

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Because we do not own these third-party pipelines or other facilities, their continuing operation is not within our control. If these pipelines or facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or other causes, we and our customers would have reduced capacity to transport, store or deliver natural gas or NGL products to end use markets or to receive deliveries of mixed NGLs, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect or in operations on third-party pipelines or facilities that would cause a material reduction in volumes transported on our pipelines or our gathering systems or processed, fractionated, treated or stored at our facilities could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Legal and regulatory proceedings and investigations relating to the energy industry have adversely affected our business and may continue to do so. The operation of our businesses might also be adversely affected by changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.

Public and regulatory scrutiny of the energy industry has resulted in the proposal and/or implementation of increased regulations. Such scrutiny has also resulted in various inquiries, investigations and court proceedings, including litigation of energy industry matters. Both the shippers on our pipelines and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.

Certain inquiries, investigations and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines and/or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our results of operations or increase our operating costs in other ways. Current legal proceedings or other matters, including environmental matters, suits, regulatory appeals and similar matters might result in adverse decisions against us which, among other outcomes, could result in the imposition of substantial penalties and fines and could

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damage our reputation. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

In addition, existing regulations might be revised or reinterpreted, and new laws and regulations might be adopted or become applicable to us, our facilities or our customers. If new laws or regulations are imposed relating to oil and gas extraction, or if additional levels of reporting, regulation or permitting moratoria are required or imposed, including those related to hydraulic fracturing, the volumes of natural gas and other products that we transport, gather, process and treat could decline and our results of operations could be adversely affected.

Certain of our gas pipeline services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.

Our gas pipelines provide some services pursuant to long-term, fixed price contracts. It is possible that costs to perform services under such contracts will exceed the revenues our pipelines collect for their services. Although most of the services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.

Our operating results for certain components of our business might fluctuate on a seasonal basis.

Revenues from certain components of our business can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and pipeline systems and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns.

We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

We do not own all of the land on which our pipelines and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. In those instances in which we do not own the land on which our facilities are located, we obtain the rights to construct and operate our pipelines and gathering systems on land owned by third parties and governmental agencies for a specific period of time. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited term. We may not have the right of eminent domain over land owned by Native American tribes. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Difficult conditions in the global financial markets and the economy in general could negatively affect our business and results of operations.

Our businesses may be negatively impacted by adverse economic conditions or future disruptions in global financial markets. Included among these potential negative impacts are industrial or economic contraction leading to reduced energy demand and lower prices for our products and services and increased difficulty in collecting amounts owed to us by our customers. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have recently been affected by concerns over U.S. fiscal policy, including uncertainty regarding federal spending and tax policy, as well as the U.S. federal government’s debt ceiling and the federal deficit. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manners described above.

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A downgrade of our credit ratings, which are determined outside of our control by independent third parties, could impact our liquidity, access to capital and our costs of doing business.

A downgrade of our credit ratings might increase our cost of borrowing and could require us to provide collateral to our counterparties, negatively impacting our available liquidity. In addition, our ability to access capital markets could be limited by a downgrade of our credit ratings as well as by economic, market or other disruptions. Credit rating agencies perform independent analysis when assigning credit ratings. This analysis includes a number of criteria such as, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the ratings agencies.

We are exposed to the credit risk of our customers and counterparties, and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy or are required to make prepayments or provide security to satisfy credit concerns. However, our credit procedures and policies may not be adequate to fully eliminate customer and counterparty credit risk. Our customers and counterparties include industrial customers, local distribution companies, natural gas producers and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur, and, if significant, could have a material adverse effect on our business, results of operations, cash flows and financial condition.

Restrictions in our debt agreements and the amount of our indebtedness may affect our future financial and operating flexibility.

Our total outstanding long-term debt (including current portion) as of December 31, 2013, was $11,354 million.

The agreements governing our indebtedness contain covenants that restrict our and our material subsidiaries’ ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to make certain distributions during the continuation of an event of default, the ability of our subsidiaries to incur additional debt, and our and our material subsidiaries’ ability to enter into certain affiliate transactions and certain restrictive agreements. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply.

Our debt service obligations and the covenants described above could have important consequences. For example, they could:

• Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;

• Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes;

• Diminish our ability to withstand a continued or future downturn in our business or the economy generally;

• Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, the payments of dividends, general corporate purposes or other purposes;

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• Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate, including limiting our ability to expand or pursue our business activities and preventing us from engaging in certain transactions that might otherwise be considered beneficial to us.

Our ability to comply with our debt covenants, to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to comply with these covenants, meet our debt service obligations or obtain future credit on favorable terms, or at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

Our failure to comply with the covenants in the documents governing our indebtedness could result in events of default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Management’s Discussion and Analysis of Financial Condition and Liquidity”.

Institutional knowledge residing with current employees nearing retirement eligibility or with our former employees might not be adequately preserved.

We expect that a significant percentage of employees will become eligible for retirement over the next three years. In certain areas of our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age or their services are no longer available to us, we may not be able to replace them with employees of comparable knowledge and experience. In addition, we may not be able to retain or recruit other qualified individuals, and our efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.

Our hedging activities might not be effective and could increase the volatility of our results.

In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered, and may in the future enter into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used and may in the future use fixed-price, forward, physical purchase and sales contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted. The Dodd-Frank Act provides for statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be transacted on exchanges for which cash collateral will be required. These new rules and regulations could increase the cost of derivative contracts or reduce the availability of derivatives. Although we believe the derivative contracts that we enter into should not be impacted by position limits and should to a large extent be exempt from the requirement to trade these transactions on exchanges and to clear these transactions through a central clearing house or to post collateral, the impact upon our businesses will depend on the

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outcome of the implementing regulations that are continuing to be adopted by the Commodities Futures Trading Commission.

A number of our financial derivative transactions used for hedging purposes are currently executed on exchanges and cleared through clearing houses that already require the posting of margins based on initial and variation requirements. Final rules promulgated under the Dodd-Frank Act may require us to post additional cash or new margin to the clearing house or to our counterparties in connection with our hedging transactions. Posting such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures or other corporate purposes. A requirement to post cash collateral could therefore reduce our ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

Our costs and funding obligations for our defined benefit pension plans and costs for our other postretirement benefit plans are affected by factors beyond our control.

We have defined benefit pension plans covering substantially all of our U.S. employees and other post-retirement benefit plans covering certain eligible participants. The timing and amount of our funding requirements under the defined benefit pension plans depend upon a number of factors that we control, including changes to pension plan benefits, as well as factors outside of our control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase our funding requirements could have a significant adverse effect on our financial condition and results of operations.

One of our subsidiaries acts as the general partner of a publicly traded limited partnership, Williams Partners L.P. As such, this subsidiary’s operations may involve a greater risk of liability than ordinary business operations.

One of our subsidiaries acts as the general partner of WPZ, a publicly traded limited partnership. This subsidiary may be deemed to have undertaken fiduciary obligations with respect to WPZ as the general partner and to the limited partners of WPZ. Activities determined to involve fiduciary obligations to other persons or entities typically involve a higher standard of conduct than ordinary business operations and therefore may involve a greater risk of liability, particularly when a conflict of interest is found to exist. Our control of the general partner of WPZ may increase the possibility of claims of breach of fiduciary duties, including claims brought due to conflicts of interest (including conflicts of interest that may arise between WPZ, on the one hand, and its general partner and that general partner’s affiliates, including us, on the other hand). Any liability resulting from such claims could be material.

Our investments and projects located outside of the United States expose us to risks related to the laws of other countries, and the taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. These risks might delay or reduce our realization of value from our international projects.

We currently own and might acquire and/or dispose of material energy-related investments and projects outside the United States. The economic, political and legal conditions and regulatory environment in the countries in which we have interests or in which we might pursue acquisition or investment opportunities present risks that are different from or greater than those in the United States. These risks include, among others, delays in construction and interruption of business, as well as risks of renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, including with respect to the prices we realize for the commodities we produce and sell. The uncertainty of the legal environment in certain foreign countries in which we develop or acquire projects or make investments could make it more difficult to obtain nonrecourse project financing or other financing on suitable terms, could adversely affect the ability of certain customers to honor their obligations with respect to such projects or investments and could impair our ability to enforce our rights under agreements relating to such projects or investments.

Operations and investments in foreign countries also can present currency exchange rate and convertibility, inflation and repatriation risk. In certain situations under which we develop or acquire projects or make investments, economic and monetary conditions and other factors could affect our ability to convert to U.S. dollars our earnings denominated in foreign currencies. In addition, risk from fluctuations in currency exchange rates can arise when our foreign subsidiaries expend or borrow funds in one type of currency, but receive revenue in another. In such cases, an adverse change in exchange rates can reduce our ability to meet expenses, including debt service obligations. We may or may

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not put contracts in place designed to mitigate our foreign currency exchange risks. We have some exposures that are not hedged and which could result in losses or volatility in our results of operations.

Failure of our service providers or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.

Certain of our accounting and information technology services are currently provided by third party vendors, and sometimes from service centers outside of the United States. Service provided pursuant to these agreements could be disrupted. Similarly, the expiration of such agreements or the transition of services between providers could lead to loss of institutional knowledge or service disruptions.

If there is a determination that the spin-off of WPX Energy, Inc (WPX) stock to our stockholders is taxable for U.S. federal income tax purposes because the facts, representations or undertakings underlying an IRS private letter ruling or a tax opinion are incorrect or for any other reason, then we and our stockholders could incur significant income tax liabilities.

In connection with our original separation plan that called for an initial public offering (IPO) of stock of WPX and a subsequent spin-off of our remaining shares of WPX to our stockholders, we obtained a private letter ruling from the IRS and an opinion of our outside tax advisor, to the effect that the distribution by us of WPX shares to our stockholders, and any related restructuring transaction undertaken by us, would not result in recognition for U.S. federal income tax purposes, of income, gain or loss to us or our stockholders under section 355 and section 368(a)(1)(D) of the Code, except for cash payments made to our stockholders in lieu of fractional shares of WPX common stock. In addition, we received an opinion from our outside tax advisor to the effect that the spin-off pursuant to our revised separation plan which was ultimately consummated on December 31, 2011, which did not involve an IPO of WPX shares, would not result in the recognition, for federal income tax purposes, of income, gain or loss to us or our stockholders under section 355 and section 368(a)(1)(D) of the Code, except for cash payments made to our stockholders in lieu of fractional shares of WPX. The private letter ruling and opinion have relied on or will rely on certain facts, representations, and undertakings from us and WPX regarding the past and future conduct of the companies’ respective businesses and other matters. If any of these facts, representations, or undertakings are, or become, incorrect or are not otherwise satisfied, including as a result of certain significant changes in the stock ownership of us or WPX after the spin-off, or if the IRS disagrees with any such facts and representations upon audit, we and our stockholders may not be able to rely on the private letter ruling or the opinion of our tax advisor and could be subject to significant income tax liabilities.

The spin-off may expose us to potential liabilities arising out of state and federal fraudulent conveyance laws and legal dividend requirements that we did not assume in our agreements with WPX.

The spin-off is subject to review under various state and federal fraudulent conveyance laws. A court could deem the spin-off or certain internal restructuring transactions undertaken by us in connection with the separation to be a fraudulent conveyance or transfer. Fraudulent conveyances or transfers are defined to include transfers made or obligations incurred with the actual intent to hinder, delay or defraud current or future creditors or transfers made or obligations incurred for less than reasonably equivalent value when the debtor was insolvent, or that rendered the debtor insolvent, inadequately capitalized or unable to pay its debts as they become due. A court could void the transactions or impose substantial liabilities upon us, which could adversely affect our financial condition and our results of operations. Whether a transaction is a fraudulent conveyance or transfer will vary depending upon the jurisdiction whose law is being applied. Under the separation and distribution agreement between us and WPX, from and after the spin-off, each of WPX and we are responsible for the debts, liabilities and other obligations related to the business or businesses which each owns and operates. Although we do not expect to be liable for any such obligations not expressly assumed by us pursuant to the separation and distribution agreement, it is possible that a court would disregard the allocation agreed to between the parties, and require that we assume responsibility for obligations allocated to WPX, particularly if WPX were to refuse or were unable to pay or perform the subject allocated obligations.

Item 1B. Unresolved Staff Comments

Not applicable.

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Item 2. Properties

Please read “Business” for a description of the location and general character of our principal physical properties. We generally own our facilities, although a substantial portion of our pipeline and gathering facilities is constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across properties owned by others.

Item 3. Legal Proceedings

Environmental

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

In September 2007, the EPA requested, and Transco later provided, information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of Transco’s compliance with the Clean Air Act. On March 28, 2008, the EPA issued notices of violation alleging violations of Clean Air Act requirements at these compressor stations. Transco met with the EPA in May 2008 and submitted a response denying the allegations in June 2008. In May 2011, Transco provided additional information to the EPA pertaining to these compressor stations in response to a request they had made in February 2011. In August 2010, the EPA requested, and Transco provided, similar information for a compressor station in Maryland. Since 2011 we have not received any additional requests for information related to these facilities.

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. On January 9, 2014, the NMED withdrew the Notice of Violation and advised that no further action is required.

Other

The additional information called for by this item is provided in Note 17 – Contingent Liabilities and Commitments of the Notes to Consolidated Financial Statements included under Part II, Item 8. Financial Statements of this report, which information is incorporated by reference into this item.

Item 4. Mine Safety Disclosures

Not applicable.

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Executive Officers of the Registrant

The name, age, period of service, and title of each of our executive officers as of February 21, 2014, are listed below.

Alan S. Armstrong	Director, Chief Executive Officer, and President
	Age: 51
	Position held since January 2011.
	From 2002 to 2011, Mr. Armstrong served as Senior Vice President - Midstream and acted as President of our midstream business. From 1999 to 2002, Mr. Armstrong was Vice President, Gathering and Processing in our midstream business and from 1998 to 1999 was Vice President, Commercial Development. Since 2012, Mr.  Armstrong has served as a director of Access GP, the general partner of ACMP, a midstream natural gas service provider. Mr. Armstrong has served as a director of BOK Financial Corporation, a financial services company, since April 2013. Since 2011, Mr. Armstrong has also served as Chairman of the Board and Chief Executive Officer of the general partner of WPZ, where he served as Senior Vice President - Midstream from 2010, and Chief Operating Officer and a director from 2005.

Francis (Frank) E. Billings	Senior Vice President — Corporate Strategic Development
	Age: 51
	Position held since January 2014.
	Mr. Billings served as a Senior Vice President - Northeast G&P from January 2013 to January 2014. Mr. Billings served as Vice President of our midstream gathering and processing business from 2011 until 2013 and as Vice President, Business Development from 2010 to 2011. Mr. Billings served as President of Cumberland Plateau Pipeline Company, a privately held company developing an ethane pipeline to serve the Marcellus shale area, from 2009 until 2010. From 2008 to 2009, Mr. Billings served as Senior Vice President of Commercial for Crosstex Energy, Inc. and Crosstex Energy L.P., an independent midstream energy services master limited partnership and its parent corporation. In 1988, Mr. Billings joined MAPCO Inc., which merged with a Williams subsidiary in 1998, serving in various management roles, including in 2008 as a Vice President in the midstream business. Mr. Billings is also the Senior Vice President - Corporate Strategic Development of the general partner of WPZ.

Allison G. Bridges	Senior Vice President — West
	Age: 54
	Position held since January 2013.
	Ms. Bridges served as the Vice President and General Manager of Williams Gas Pipeline - West from 2010 until 2013. From 2003 to 2010, Ms. Bridges was Vice President Commercial Operations for Northwest Pipeline. Ms. Bridges joined Transco in 1981, now a subsidiary of us and WPZ, holding various management positions in accounting, rates, planning and business development. Ms. Bridges is also the Senior Vice President - West of the general partner of WPZ. Ms. Bridges has served as a member of the Management Committee of Northwest Pipeline since 2007.

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Donald R. Chappel	Senior Vice President and Chief Financial Officer
	Age: 62
	Position held since April 2003.
	Prior to joining us, Mr. Chappel held various financial, administrative and operational leadership positions. Since 2012, Mr. Chappel has served as a director of Access GP, the general partner of ACMP, in which we own an interest. Mr. Chappel has also served as a member of the Management Committee of Northwest Pipeline since 2007. Mr. Chappel was Chief Financial Officer from 2007 and a director from 2008 of Williams Pipeline GP LLC, the general partner of Williams Pipeline Partners L.P., until its merger with WPZ in 2010. Mr. Chappel is a director of SUPERVALU, Inc. (a grocery and pharmacy company). Mr. Chappel also serves as Chief Financial Officer and a director of the general partner of WPZ.

John R. Dearborn	Senior Vice President - NGL & Petchem Services
	Age: 56
	Position held since April 2013.
	Mr. Dearborn served as a senior leader for Saudi Basic Industries Corporation, a petrochemical company, from 2011 to 2013. From 2001 to 2011, Mr. Dearborn served in a variety of leadership positions with the Dow Chemical Company (DOW). Mr. Dearborn also worked for Union Carbide Corporation, prior to its merger with DOW, from 1981 to 2001 where he served in several leadership roles. Mr. Dearborn also serves as Senior Vice President - NGL & Petchem Services of the general partner of WPZ.

Robyn L. Ewing	Senior Vice President and Chief Administrative Officer
	Age: 58
	Position held since April 2008.
	From 2004 to 2008, Ms. Ewing was Vice President of Human Resources. Prior to joining Williams, Ms. Ewing worked at MAPCO, which merged with Williams in 1998. Ms. Ewing began her career with Cities Service Company in 1976.

Rory L. Miller	Senior Vice President — Atlantic — Gulf
	Age: 53
	Position held since January 2013.
	From 2011 until 2013, Mr. Miller served as Senior Vice President - Midstream of us and the general partner of WPZ, acting as President of our midstream business. Mr. Miller was a Vice President of our midstream business from 2004 until 2011. Mr. Miller also serves as a director and as Senior Vice President - Atlantic-Gulf of the general partner of WPZ. Mr. Miller has served as a member of the Management Committee of Transco since 2013.

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Fred E. Pace	Senior Vice President — E&C (Engineering and Construction)
	Age: 52
	Position held since January 2013.
	From 2011 until 2013, Mr. Pace served Williams in project engineering and development roles, including service as Vice President Engineering and Construction for our midstream business. From 2009 to 2011, Mr. Pace was the managing member of PACE Consulting, LLC, an engineering and consulting firm serving the energy industry. In 2003, Mr. Pace co-founded Clear Creek Natural Gas, LLC, later known as Clear Creek Energy Services, LLC, a provider of engineering, construction, and operational services to the energy industry where he served as Chief Executive Officer until 2009. Mr. Pace has over 30 years of experience in the engineering, construction, operation, and project management areas of the energy industry, including prior service with Williams from 1985 to 1990. Mr. Pace also serves as Senior Vice President - E&C of the general partner of WPZ.

Brian L. Perilloux	Senior Vice President — Operational Excellence
	Age: 52
	Position held since January 2013.
	Mr. Perilloux served as a Vice President of our midstream business from 2011 until 2013. From 2007 to 2011, Mr. Perilloux served in various roles in our midstream business, including engineering and construction roles. Prior to joining Williams, Mr. Perilloux was an officer of a private international engineering and construction company. Mr. Perilloux also serves as Senior Vice President - Operational Excellence of the general partner of WPZ.

Craig L. Rainey	Senior Vice President and General Counsel
	Age: 61
	Position held since January 2012.
	Mr. Rainey has served as Senior Vice President and General Counsel since January 2012. From 2001 to 2012, Mr. Rainey served as an Assistant General Counsel of Williams, primarily supporting our midstream business and former exploration and production business. Mr. Rainey joined Williams in 1999 as a senior counsel and has practiced law since 1977. Mr. Rainey is also the General Counsel of the general partner of WPZ.

James E. Scheel	Senior Vice President — Senior Vice President - Northeast G&P
	Age: 49
	Position held since January 2014.
	From 2012 to 2014 Mr. Scheel served as Senior Vice President - Corporate Strategic Development. From 2011 until 2012, Mr. Scheel served as Vice President of Business Development for our midstream business. Mr. Scheel joined Williams in 1988 and has served in leadership roles in business strategic development, engineering and operations, our NGL business, and international operations. Since 2012, Mr. Scheel has served as a director of Access GP, the general partner of ACMP, in which we own an interest. Mr. Scheel also serves as a director and as Senior Vice President - Northeast G&P of the general partner of WPZ.

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Ted T. Timmermans	Vice President, Controller, and Chief Accounting Officer
	Age: 57
	Position held since July 2005.
	Mr. Timmermans served as Assistant Controller of Williams from April 1998 to July 2005. Mr. Timmermans is also Vice President, Controller & Chief Accounting Officer of the general partner of WPZ and served as Chief Accounting Officer of Williams Pipeline Partners GP LLC, the general partner of Williams Pipeline Partners L.P. from January 2008 until its merger with WPZ in August 2010.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed on the New York Stock Exchange under the symbol “WMB.” At the close of business on February 21, 2014, we had approximately 8,405 holders of record of our common stock. The high and low sales price ranges (New York Stock Exchange composite transactions) and dividends declared by quarter for each of the past two years are as follows:

	High		Low		Dividend
2013
First Quarter	$	38.00	$	33.09	$	0.33875
Second Quarter	38.57		31.25		0.3525
Third Quarter	36.94		32.36		0.36625
Fourth Quarter	38.68		33.98		0.38
2012
First Quarter	$	32.09	$	26.21	$	0.25875
Second Quarter	34.63		27.25		0.30
Third Quarter	35.39		28.47		0.3125
Fourth Quarter	37.56		30.55		0.325

Some of our subsidiaries’ borrowing arrangements may limit the transfer of funds to us. These terms have not impeded, nor are they expected to impede, our ability to pay dividends.

Performance Graph

Set forth below is a line graph comparing our cumulative total stockholder return on our common stock (assuming reinvestment of dividends) with the cumulative total return of the S&P 500 Stock Index and the Bloomberg U.S. Pipeline Index for the period of five fiscal years commencing January 1, 2009. The Bloomberg U.S. Pipeline Index is composed of Enbridge, Kinder Morgan, Inc., Kinder Morgan Management, LLC, ONEOK, Inc., Spectra Energy, TransCanada Corp., and Williams. The graph below assumes an investment of $100 at the beginning of the period.

	2008	2009	2010	2011	2012	2013
The Williams Companies, Inc.	100.0	149.8	179.8	246.4	310.9	381.0
S&P 500 Index	100.0	126.5	145.5	148.6	172.3	228.0
Bloomberg U.S. Pipelines Index	100.0	141.7	174.3	240.3	272.6	302.7

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Item 6. Selected Financial Data

The following financial data at December 31, 2013 and 2012, and for each of the three years in the period ended December 31, 2013, should be read in conjunction with the other financial information included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting records.

	2013		2012		2011		2010		2009
	(Millions, except per-share amounts)
Revenues	$	6,860	$	7,486	$	7,930	$	6,638	$	5,278
Income (loss) from continuing operations (1)	679		929		1,078		271		346
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations (1)	441		723		803		104		206
Diluted earnings (loss) per common share:
Income (loss) from continuing operations (1)	0.64		1.15		1.34		0.17		0.35
Total assets at December 31 (2) (3)	27,142		24,327		16,502		24,972		25,280
Commercial paper and long-term debt due within one year at December 31 (4)	226		1		353		508		17
Long-term debt at December 31 (3)	11,353		10,735		8,369		8,600		8,259
Stockholders’ equity at December 31 (2) (3)	4,864		4,752		1,296		6,803		7,990
Cash dividends declared per common share	1.438		1.196		0.775		0.485		0.44

_________

(1) Income from continuing operations for 2013 includes $99 million of deferred income tax expense incurred on undistributed earnings of our foreign operations that are no longer considered permanently reinvested. 2011 includes $271 million of pre-tax early debt retirement costs, and 2010 includes $648 million of debt retirement and other pre-tax costs associated with our strategic restructuring transaction in the first quarter of 2010.

(2) Total assets and stockholders’ equity for 2011 decreased due to the special dividend to spin off our former exploration and production business.

(3) The increases in 2012 reflect assets and investments acquired, primarily related to the Caiman and Laser Acquisitions and our investment in Access Midstream Partners, as well as debt and equity issuances.

(4) The increase in 2013 reflects borrowings under WPZ’s commercial paper program initiated in 2013.

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Item 7. 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, 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 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 December 31, 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 Gulf Coast Region, and areas of increasing natural gas demand.

Williams Partners’ interstate transmission and related storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have little near-term impact on 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 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 certain other domestic olefins pipeline assets including 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 ACMP, acquired in December 2012. As of December 31, 2013, this investment includes a 23 percent limited partner interest in ACMP and a 50 percent indirect interest in Access GP, including incentive distribution rights. ACMP is a publicly traded master limited partnership that owns, operates, develops, and acquires natural gas gathering systems and other midstream energy assets, which bolsters our position in the Marcellus and Utica shale plays and adds diversity via the Eagle Ford, Haynesville, Barnett, Mid-Continent, and Niobrara areas.

Unless indicated otherwise, the following discussion and analysis of critical accounting estimates, results of operations, and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this document.

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Canada Dropdown

In February 2014, WPZ agreed to acquire certain of our Canadian operations, including an oil sands offgas processing plant near Fort McMurray, Alberta, an NGL/olefin fractionation facility and B/B splitter facility at Redwater, Alberta, and the Boreal pipeline. The transaction is expected to close in February of 2014. These businesses are currently reported within our Williams NGL & Petchem Services segment. WPZ expects to fund the transaction with $25 million of cash, the issuance of 25,577,521 Class D limited-partner units, and an increase in the capital account of its general partner to allow us to maintain our 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units, all of which will be convertible to common units at a future date. The agreement also provides that WPZ can issue additional Class D units to us on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions.

Dividend Growth

We increased our quarterly dividends from $0.325 per share in the fourth quarter of 2012 to $0.380 per share in the fourth quarter of 2013. Also, consistent with our expectation of receiving increasing cash distributions from our interests in WPZ and Access Midstream Partners, we expect to increase our dividend on a quarterly basis. Our Board of Directors has approved a dividend of $0.4025 per share for the first quarter of 2014 and we expect approximately 20 percent annual increase in total dividends in both 2014 and 2015.

Overview

Income (loss) from continuing operations attributable to The Williams Companies, Inc., for the year ended December 31, 2013, changed unfavorably by $282 million compared to the year ended December 31, 2012. This change primarily reflects a $206 million decline in Williams Partners segment profit primarily due to lower NGL margins driven by reduced ethane recoveries and lower olefins margins as a result of the Geismar Incident, partially offset by higher fee-based revenues; $61 million in segment profit from our investment in ACMP acquired at the end of 2012; and $99 million of deferred income tax expense recognized in 2013 related to undistributed earnings of certain foreign operations that are no longer considered permanently reinvested. See additional discussion in Results of Operations.

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

Williams Partners

Geismar Incident

On June 13, 2013, an explosion and fire occurred at WPZ’s Geismar olefins plant. The fire was extinguished on the day of the incident. The 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 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.

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We are cooperating with the Chemical Safety Board and the EPA regarding their investigations of the Geismar Incident. While certain negotiations pertaining to various citations and assessments remain ongoing with the Occupational Safety and Health Administration (OSHA), they have released the incident area back to us, and we are in the process of repairing the damage incurred. We have expensed $13 million of costs in 2013 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. During the fourth quarter of 2013, we incurred $10 million of covered insurable expenses in excess of our retentions (deductibles) which partially offset the $50 million of insurance proceeds received during the third quarter of 2013, which was reported as a gain in 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 in June 2014. We expect our insurance coverage will significantly mitigate our financial loss. We currently estimate approximately $430 million of total cash recoveries from insurers related to business interruption and approximately $70 million related to the repair of the plant. Of these amounts, we received $50 million of insurance proceeds during 2013. In February 2014, the insurer agreed to pay a second installment of $125 million, which is expected to be received in the first quarter of 2014. We are impacted by certain uninsured losses, including amounts associated with the 60-day waiting period for business interruption, as well as other deductibles, policy limits, and uninsured expenses. Our assumptions and estimates, including the timing for the expanded plant return to operation, repair cost estimates, and insurance proceeds associated with our property damage and business interruption coverage are subject to various risks and uncertainties that could cause the actual results to be materially different.

Mid-Atlantic Connector

The Mid-Atlantic Connector Project involved 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. We placed the project into service in the first quarter of 2013, and it increased capacity by 142 Mdth/d.

Overland Pass Pipeline

Through our equity investment in 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 NGL volumes to OPPL from the Bakken Shale in the Williston basin.

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 is expected to 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. Further development has been delayed pending additional evaluation of producers’ drilling plans.

Gulfstar One

Effective April 1, 2013, WPZ sold a 49 percent interest in Gulfstar One LLC (Gulfstar One) 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 the third quarter 2014. In December 2013, Gulfstar One agreed to host the Gunflint development, which will result in an expansion

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of the Gulfstar One system to provide production handling capacity of 20 Mbbls/d and 40 MMcf/d for Gunflint. The project has a first oil target of mid-2016, dependent on the producer’s development activities.

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 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.

Mid-South

The Mid-South expansion project involved an expansion of Transco’s mainline from Station 85 in Choctaw County, Alabama to markets as far downstream as North Carolina. We placed the first phase of the project into service in the third quarter of 2012, which increased capacity by 95 Mdth/d. The second phase was placed into service in the second quarter of 2013, which increased capacity by an additional 130 Mdth/d.

Northeast Supply Link

The Northeast Supply Link Project involved an expansion of 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. The project was placed into service in the fourth quarter of 2013 and increased capacity by 250 Mdth/d.

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, Transco filed a stipulation and agreement with the FERC proposing to resolve all issues in this proceeding without the need for a hearing (Agreement). On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds of $98 million which we believe is adequate for required refunds as of December 31, 2013, under the Agreement. Refunds will be made on or before April 30, 2014.

Caiman II

As a result of planned contributions through the second quarter of 2014, we expect, subject to regulatory approval, to increase our ownership in Caiman II from 47.5 percent up to approximately 59 percent. These additional contributions are used to fund a portion of Blue Racer Midstream, a joint project which comprises an expansion to gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica Shale.

Atlantic Sunrise

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

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Volume impacts in 2013

Due to unfavorable ethane economics, we reduced our recoveries of ethane in our plants during most of 2013, which resulted in 31 percent lower NGL production volumes and 48 percent lower NGL equity sales volumes in 2013 compared to 2012.

As a result of the Geismar Incident, ethylene sales volumes have decreased 56 percent in 2013 compared to 2012.

Volatile commodity prices

NGL margins were approximately 40 percent lower in 2013 compared to 2012 driven by reduced ethane recoveries, as previously mentioned, coupled with lower NGL prices and higher natural gas prices, and the absence of hedge gains recognized in 2012, which primarily increased our realized non-ethane sales prices. However, our average per-unit composite NGL margin in 2013 has increased slightly compared to 2012 as the relative mix of NGL products produced has shifted to a greater proportion of higher-margin non-ethane products.

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

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

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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 is expected to produce approximately 1.1 billion pounds annually, significantly increasing Williams’ production of polymer-grade propylene currently at 180 million pounds annually. The project is in the development stage and is expected to start-up in the second quarter of 2017. This project is not part of the Canadian operations that are expected to be acquired by WPZ.

Bluegrass Pipeline and Moss Lake

In the second quarter of 2013, we formed a joint project to develop the Bluegrass Pipeline. We own a 50 percent percent interest in Bluegrass Pipeline (a consolidated entity), 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 proposed 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 in discussions with potential customers regarding the commitments to the pipeline. Completion of this project is subject to all necessary or required approvals, elections, and actions, as well as execution of formal customer commitments. We currently estimate that the Bluegrass Pipeline will be placed in-service in mid-to-late 2016.

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.

Ethane Recovery Project

In December 2013, we completed the ethane recovery project, which is an expansion of our Canadian facilities which allows us to recover ethane/ethylene mix from our operations that process offgas from the Alberta oil sands. We modified our oil sands offgas extraction plant near Fort McMurray, Alberta, and constructed a deethanizer at our Redwater fractionation facility that processes 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. This project is included in the Canadian operations that are expected to be acquired by WPZ.

Company Outlook

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

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

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

Our business plan for 2014 reflects both significant capital investment and continued dividend growth. Our planned consolidated capital investments for 2014 total approximately $4.6 billion. We also expect approximately 20 percent

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growth in total 2014 dividends, which we expect to fund primarily with distributions received from WPZ and ACMP. We expect to maintain an attractive cost of capital and reliable access to capital markets, both of which will allow us to pursue development projects and acquisitions.

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

• General economic, financial markets, or industry downturn;

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

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

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

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

• Counterparty credit and performance risk;

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

• Lower than anticipated energy commodity prices and margins;

• Changes in the political and regulatory environments;

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

• Reduced availability of insurance coverage.

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

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

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

Williams Partners

Commodity price changes

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

In 2014, we anticipate higher overall commodity prices compared to 2013:

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

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

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

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

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

Gathering, processing, and NGL sales volumes

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

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

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

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

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

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

Olefin production volumes

Williams Partners’ Gulf olefins business anticipates higher ethylene volumes in 2014 compared to 2013 substantially due to the repair and expansion of the Geismar plant expected to be in operation in the second quarter of 2014.

Other

• Williams Partners’ Gulf olefins business expects to receive insurance recoveries under its business interruption policy related to the Geismar Incident that will favorably impact our operating results in 2014.

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

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

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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 remaining cost to complete the abandonment of the caverns will be approximately $7 million, and is expected to be spent through the first half of 2014.

As of December 31, 2013, we have incurred approximately $93 million of these abandonment costs. Management considers these costs to be prudent costs incurred in the abandonment of these caverns. Consistent with the terms of the recent rate case, we expensed $12 million in 2013 related to a portion of the Eminence abandonment regulatory asset that will not be recovered in rates. We have also recognized income of $16 million in 2013 related to insurance recoveries associated with this event.

Williams NGL & Petchem Services

Commodity margin and volume changes

While per-unit margins, including propylene and ethylene, are volatile and highly dependent upon continued demand within the global economy, we expect to benefit in the broader global petrochemical markets because of our strategic advantage in propylene production from oil sands offgas. We believe that our gross commodity margins will be higher than 2013 levels due to the following:

• Propylene volumes are expected to be higher than 2013 levels following a planned turnaround to conduct maintenance and to complete the ethane recovery project tie-in during 2013.

• We anticipate new ethane volumes in 2014 associated with the completion of our ethane recovery project in the fourth quarter of 2013, which is an expansion of our Canadian facilities that allows us to recover ethane from our operations that process offgas from the Alberta oil sands. Additionally, we expect to benefit from a contractual minimum ethane sales price.

• We expect propane prices to be higher than 2013, slightly offset by higher natural gas prices.

Access Midstream Partners

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

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

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Expansion Projects

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

	Low		High
	(Millions)
Segment:
Williams Partners	$	3,025	$	3,525
Williams NGL & Petchem Services	775		1,075

Our ongoing major expansion projects include the following:

Williams Partners

Atlantic Sunrise

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

Leidy Southeast

In September 2013, we filed an application with the FERC for Transco’s Leidy Southeast Expansion project to expand our existing natural gas transmission system from the Marcellus Shale production region on Transco’s Leidy Line in Pennsylvania to delivery points along its mainline as far south as Station 85 in Alabama. We plan to place the project into service during the fourth quarter of 2015, and expect it to increase capacity by 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 during the second quarter of 2015 and it is expected to increase capacity on the line by 225 Mdth/d.

Constitution Pipeline

In June 2013, we filed an application with the FERC for authorization to construct and operate the new jointly owned Constitution pipeline. We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will be the operator of Constitution. The 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 late 2015 to 2016, 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 it to increase capacity by 100 Mdth/d.

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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, the capacity of the lateral is expected to be 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 during the third quarter of 2015, and expect it to increase capacity by 270 Mdth/d.

Marcellus Shale Expansions

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

• 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.

• Expansions to the Laurel Mountain gathering system infrastructure to increase the capacity to 667 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 II equity investment. Expansion plans include the addition of Natrium II, a second 200 MMcf/d processing plant at Natrium by the end of the first quarter of 2014. Construction of an additional 200 MMcf/d processing plant is underway at the Berne complex in Monroe County, Ohio. Berne I is expected to come online in the third quarter of 2014.

Gulfstar One

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 the third quarter 2014. The previously discussed expansion that increases Gulfstar One’s production handling capacity related to the Gunflint Development is expected to be completed in mid-2016, dependent on the producer’s development activities.

Parachute

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

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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 June 2014. The expansion is expected to increase the facility’s ethylene production capacity by 600 million pounds per year to a new annual capacity of 1.95 billion pounds. The additional capacity will be wholly owned by us and is expected to increase our ownership of the Geismar production facility from the current 83.3 percent.

Keathley Canyon Connector™

Discovery is constructing a 215-mile, 20-inch deepwater lateral pipeline in the central deepwater Gulf of Mexico that it will own and operate. Discovery has signed long-term agreements with anchor customers for natural gas gathering and processing services for production from the Keathley Canyon and Green Canyon areas. The Keathley Canyon Connector™ lateral will originate from a third-party floating production facility in the southeast portion of the Keathley Canyon area and will connect to Discovery’s existing 30-inch offshore natural gas transmission system. The gas will be processed at Discovery’s Larose Plant and the NGLs will be fractionated at Discovery’s Paradis Fractionator. The lateral pipeline is estimated to have the capacity to flow more than 400 MMcf/d and will accommodate the tie-in of other deepwater prospects. The pipeline is expected to be in service in the fourth quarter of 2014.

Williams NGL & Petchem Services

Canadian PDH Facility

As previously discussed, we are planning to build a PDH facility in Alberta that will significantly increase production of polymer-grade propylene. Start-up for the PDH facility is expected to occur in the second quarter of 2017.

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 2015.

Bluegrass Pipeline

As previously discussed, in the second quarter we formed a joint project to develop the proposed Bluegrass Pipeline. Pre-construction activities are under way and we currently estimate that the project will be placed in-service in mid-to-late 2016.

Critical Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We have reviewed the selection, application, and disclosure of these

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critical accounting estimates with our Audit Committee. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.

Pension and Postretirement Obligations

We have employee benefit plans that include pension and other postretirement benefits. Net periodic benefit cost and obligations for these plans are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute cost and the benefit obligations are shown in Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements.

The following table presents the estimated increase (decrease) in net periodic benefit cost and obligations resulting from a one-percentage-point change in the specific assumption.

	Benefit Cost						Benefit Obligation
	One- Percentage- Point Increase			One- Percentage- Point Decrease			One- Percentage- Point Increase			One- Percentage- Point Decrease
	(Millions)
Pension benefits:
Discount rate	$	(6	)	$	7		$	(114	)	$	133
Expected long-term rate of return on plan assets	(11		)	11			—			—
Rate of compensation increase	2			(1		)	7			(6		)
Other postretirement benefits:
Discount rate	1			1			(20		)	24
Expected long-term rate of return on plan assets	(2		)	2			—			—
Assumed health care cost trend rate	5			(4		)	7			(6		)

Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on the average rate of return expected on the funds invested in the plans. We determine our long-term expected rates of return on plan assets using our expectations of capital market results, which includes an analysis of historical results as well as forward-looking projections. These capital market expectations are based on a period of at least 10 years and take into account our investment strategy and mix of assets, which is weighted toward domestic and international equity securities. We develop our expectations using input from several external sources, including consultation with our third-party independent investment consultant. The forward-looking capital market projections are developed using a consensus of economists’ expectations for inflation, GDP growth, and dividend yield along with expected changes in risk premiums. The capital market return projections for specific asset classes in the investment portfolio are then applied to the relative weightings of the asset classes in the investment portfolio. The resulting rates are an estimate of future results and, thus, likely to be different than actual results.

In 2013, the benefit plans’ assets reflected strong equity performance as well as negative returns from the fixed income strategies. While the 2013 investment performance was greater than our expected rates of return, the expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance. Changes to our asset allocation would also impact these expected rates of return. Our expected long-term rate of return on plan assets used for our pension plans was 6.3 percent in 2012. In 2013, we reduced our expected long-term rate of return on pension assets to 5.9 percent. This reduction was implemented due to a downward trend in long-term capital market expectations. The 2013 actual return on plan assets for our pension plans was approximately 15.5 percent. The 10-year average rate of return on pension plan assets through December 2013 was approximately 5.7 percent.

The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans. The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due. Increases in the discount rates decrease the obligation and, generally, decrease the related cost. The discount rates for

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our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term, high-quality debt securities as well as by the duration of our plans’ liabilities. The weighted-average discount rate used to measure our pension plans’ benefit obligation increased during 2013 by 125 basis points, which significantly contributed to the actuarial gain of $173 million in the current year.

The expected rate of compensation increase represents average long-term salary increases. An increase in this rate causes the pension obligation and cost to increase.

The assumed health care cost trend rates are based on national trend rates adjusted for our actual historical cost rates and plan design. An increase in this rate causes the other postretirement benefit obligation and cost to increase.

Goodwill

At December 31, 2013, our Consolidated Balance Sheet includes $646 million of goodwill. We performed our annual assessment of goodwill for impairment as of October 1. All of our goodwill is allocated to WPZ’s Northeast gathering and processing business (the reporting unit). In our evaluation, our estimate of the fair value of the reporting unit exceeded its carrying value by 15 percent, including goodwill, and thus no impairment loss was recognized in 2013. The fair value of WPZ’s Northeast gathering and processing business was estimated by an income approach utilizing discounted cash flows and corroborated with a market capitalization analysis.

Judgments and assumptions are inherent in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of an impairment charge in the consolidated financial statements. Our calculation of fair value used a discount rate of 10.5 percent. We estimate that an increase of approximately 140 basis points in the discount rate could result in a fair value of the reporting unit below its carrying value, all other variables held constant.

Equity-method investments

At December 31, 2013, our Consolidated Balance Sheet includes approximately $4.4 billion of investments that are accounted for under the equity method of accounting. We evaluate these investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair value of our investments.

If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge. Events or changes in circumstances that may be indicative of an other-than-temporary decline in value will vary by investment, but may include:

• A significant or sustained decline in the market value of a publicly-traded investee;

• Lower than expected cash distributions from investees (including incentive distributions);

• Significant asset impairments or operating losses recognized by investees;

• Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees;

• Significant delays in or failure to complete significant growth projects of investees.

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No impairments of investments accounted for under the equity method have been recorded for the year ended December 31, 2013.

Capitalized project development costs

As of December 31, 2013, our Consolidated Balance Sheet includes approximately $113 million of capitalized project development costs associated with the Bluegrass Pipeline, of which our net interest is 50 percent or $56.5 million. Completion of this project is subject to execution of customer contracts sufficient to support the project. We are in discussions with potential customers regarding commitments to the pipeline and these discussions have not yet yielded sufficient commitments to satisfy this condition. As a result, we evaluated the capitalized project costs for impairment as of December 31, 2013, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including reasonably possible scenarios assuming the construction and operation of the pipeline under differing levels of commitments from customers and the possibility that the project does not proceed. It is reasonably possible that the probability-weighted estimate of undiscounted future net cash flows may change in the near term, resulting in the write down of this asset to fair value. Such changes in estimates could result from lack of sufficient commitments from potential customers, lack of approval of the project by our partner, lack of executed regulatory approvals and unexpected changes in forecasted costs, and other factors impacting project economics.

We will continue to evaluate these and other capitalized project development costs for impairment in the future if we believe events or changes in circumstances indicate that we may not be able to recover the carrying value. Should we determine in future periods that we will be unable to obtain sufficient customer commitments or fail to realize other key project variables and conclude that a project is probable of not being developed, all of the capitalized project development costs for that project would be expensed as they would no longer qualify for continued capitalization.

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Results of Operations

Consolidated Overview

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

	Years Ended December 31,
	2013			$ Change from 2012*	% Change from 2012*	2012			$ Change from 2011*	% Change from 2011*	2011
	(Millions)
Revenues:
Service revenues	$	2,939		+210	+8%	$	2,729		+197	+8%	$	2,532
Product sales	3,921			-836	-18%	4,757			-641	-12%	5,398
Total revenues	6,860					7,486					7,930
Costs and expenses:
Product costs	3,027			+469	+13%	3,496			+438	+11%	3,934
Operating and maintenance expenses	1,097			-70	-7%	1,027			-37	-4%	990
Depreciation and amortization expenses	815			-59	-8%	756			-95	-14%	661
Selling, general, and administrative expenses	512			+59	+10%	571			-94	-20%	477
Other (income) expense — net	34			-10	-42%	24			-23	NM	1
Total costs and expenses	5,485					5,874					6,063
Operating income (loss)	1,375					1,612					1,867
Equity earnings (losses)	134			+23	+21%	111			-44	-28%	155
Interest expense	(510		)	-1	0%	(509		)	+64	+11%	(573		)
Other investing income — net	81			+4	+5%	77			+64	NM	13
Early debt retirement costs	—			—	—	—			+271	+100%	(271		)
Other income (expense) — net	—			+2	+100%	(2		)	-13	NM	11
Income (loss) from continuing operations before income taxes	1,080					1,289					1,202
Provision (benefit) for income taxes	401			-41	-11%	360			-236	-190%	124
Income (loss) from continuing operations	679					929					1,078
Income (loss) from discontinued operations	(11		)	-147	NM	136			+553	NM	(417		)
Net income (loss)	668					1,065					661
Less: Net income attributable to noncontrolling interests	238			-32	-16%	206			+79	+28%	285
Net income (loss) attributable to The Williams Companies, Inc.	$	430				$	859				$	376

_______

* + = 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.

2013 vs. 2012

The increase in Service revenues is primarily due to higher fee revenues associated with the growth in the businesses acquired in the 2012 Caiman and Laser Acquisitions, 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 driven by lower volumes in the Piceance, Four Corners, and eastern Gulf Coast areas.

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The decrease in Product sales is primarily due to lower NGL production revenues driven by reduced ethane recoveries and decreases in average NGL per-unit sales prices, as well as lower olefin production revenues primarily from the loss of production as a result of the Geismar Incident, partially offset by higher olefin per-unit sales prices. Additionally, marketing revenues decreased resulting from lower NGL per-unit prices and lower crude oil and ethane volumes, partially offset by higher non-ethane volumes. The changes in marketing revenues are more than offset by similar changes in marketing purchases, reflected above as Product costs.

The decrease in Product costs is primarily due to lower NGL marketing purchases resulting from lower NGL prices and lower crude oil volumes, partially offset by higher non-ethane volumes. The changes in marketing purchases are substantially offset by similar changes in marketing revenues. In addition, olefin feedstock purchases decreased reflecting lower volumes and lower average per-unit feedstock costs. Costs associated with the production of NGLs also decreased primarily resulting from 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, a scheduled third-quarter 2013 shutdown to conduct maintenance at our Canadian olefins facility, and $13 million of costs incurred under our insurance deductibles resulting from the Geismar Incident. These increases are partially offset by lower compressor and natural gas pipeline maintenance and repair expenses primarily due to 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, which experienced lower volumes.

The increase in Depreciation and amortization expenses reflects a full year of depreciation and amortization expense in 2013 related to the Caiman and Laser Acquisitions and depreciation on subsequent infrastructure additions, increased depreciation of certain assets that were decommissioned in the third quarter of 2013 in preparation for the completion of the ethane recovery system, as well as higher depreciation on the Boreal Pipeline which was placed into service in 2012. The absence of increased depreciation in 2012 on certain assets in the Gulf Coast region resulting from a change in the estimated useful lives partially offset these increases.

The decrease in Selling, general, and administrative expenses (SG&A) is primarily due to the absence of reorganization related costs in 2012 and the absence of acquisition and transition costs incurred in 2012. (See Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements.)

Other (income) expense – net within Operating income includes the following increases to net expense:

• $25 million accrued loss for a settlement in principle of a producer claim against us;

• $23 million increase in amortization expense related to our regulatory asset associated with asset retirement obligations;

• $20 million write-off of development costs of an abandoned project;

• $12 million expense recognized in 2013 related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates.

Other (income) expense – net within Operating income includes the following decreases to net expense:

• $40 million of income associated with net insurance recoveries related to the Geismar Incident in 2013;

• $16 million of income from insurance recoveries related to the abandonment of certain of Eminence storage assets in 2013;

• $9 million involuntary conversion gain recognized in 2013 related to a 2012 furnace fire for our Geismar olefins plant.

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The unfavorable change in Operating income (loss) generally reflects lower NGL production margins, lower olefin production margins, higher operating costs, the net unfavorable changes in Other (income) expense as described above, partially offset by increased fee revenues, higher marketing margins, and lower SG&A expenses.

The favorable change in Equity earnings (losses) is primarily due to higher equity earnings from Access Midstream Partners resulting from the acquisition of this investment in late 2012 and improved equity earnings from Laurel Mountain. These increases are partially offset by lower equity earnings from Discovery.

Interest expense increased due to a $42 million increase in Interest capitalized related to construction projects primarily at Williams Partners, substantially offset by a $43 million increase in Interest incurred primarily due to an increase in borrowings (see Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements).

The favorable change in Other investing income – net is primarily due to a $43 million increase in interest income associated with a receivable related to the sale of certain former Venezuela assets and gains of $31 million resulting from Access Midstream Partners' equity issuances in 2013. These increases are partially offset by 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. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)

Provision (benefit) for income taxes changed unfavorably primarily due to $99 million of deferred income tax expense recognized in 2013 related to the undistributed earnings of certain foreign operations that are no longer considered permanently reinvested. This is partially offset by a reduction in tax expense due to lower pre-tax income. See Note 7 – 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 years.

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 4 – Discontinued Operations of Notes to Consolidated Financial Statements.)

The unfavorable change in Net income attributable to noncontrolling interests primarily reflects our slightly decreased percentage of limited partner ownership of WPZ and higher operating results at 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 5 – Investing Activities of Notes to Consolidated Financial Statements.)

2012 vs. 2011

The increase in Service revenues is primarily due to higher fee revenues resulting from increased gathering and processing volumes in the Marcellus Shale, including new volumes from our assets acquired in the 2012 Caiman Acquisition and Laser Acquisition and higher volumes in the western deepwater Gulf of Mexico and in the Piceance basin. Additionally, natural gas transportation revenues increased from expansion projects placed into service in 2011 and 2012.

The decrease in Product sales is primarily due to lower NGL and olefin production revenues reflecting an overall decrease in average per-unit sales prices, and lower marketing revenues primarily due to significant decreases in NGL and olefin prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities.

The decrease in Product costs is primarily due to lower olefins feedstock costs reflecting a decrease in average per-unit prices and lower costs associated with the production of NGLs primarily resulting from a decrease in average natural gas prices. Marketing purchases also decreased primarily due to significantly lower average NGL prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities.

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The increase in Operating and maintenance expenses is primarily due to increased maintenance expenses primarily associated with assets acquired in 2012 and increased employee-related benefit costs, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.

The increase in Depreciation and amortization expenses is primarily associated with assets acquired in 2012. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets of Notes to Consolidated Financial Statements.)

The increase in SG&A is primarily due to $23 million of acquisition and transition-related costs incurred in 2012 as well as higher employee-related and information technology expenses driven by general growth within business operations. SG&A also includes $26 million of reorganization-related costs incurred in 2012 primarily relating 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) and is substantially offset by the absence of general corporate expenses related to the spin-off of WPX, which was completed on December 31, 2011.

The unfavorable change in Other (income) expense - net within Operating income (loss) primarily reflects the absence of the Gulf Liquids litigation contingency accrual reduction of $19 million in 2011. (See Note 6 – Other Income and Expenses and Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements.)

The unfavorable change in Operating income(loss) generally reflects lower NGL production and marketing margins, as well as previously described increases in Operating and maintenance expenses, Depreciation and amortization expenses, SG&A and an unfavorable change in Other (income) expense — net. Higher fee revenues and olefin production margins partially offset these decreases.

The unfavorable change in Equity earnings (losses) is primarily due to lower Laurel Mountain, Aux Sable and Discovery equity earnings primarily reflecting lower operating results of these investees and the impairment of two minor NGL processing plants at Laurel Mountain in 2012.

Interest expense decreased due to an increase in Interest capitalized related to construction projects, as well as a decrease in Interest incurred related to corporate debt retirements in December 2011, partially offset by an increase in borrowings and the absence of a $14 million reduction of an interest accrual related to a litigation contingency in 2011 as previously discussed.

The favorable change in Other investing income — net is primarily due to $63 million of income, including interest, recognized in 2012 as compared to an $11 million gain in 2011 related to the 2010 sale of our interest in Accroven SRL. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)

Early debt retirement costs in 2011 reflect costs related to corporate debt retirements in December 2011, including $254 million in related premiums.

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income, the absence of approximately $147 million tax benefit from federal settlements and an international revised assessment in 2011, and the absence of $66 million deferred tax benefit recognized in 2011 related to the undistributed earnings of certain foreign operations that we considered to be permanently reinvested. See Note 7 – 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 years.

Income (loss) from discontinued operations in 2012 primarily includes a gain on reconsolidation following the sale of certain of our former Venezuela operations. Income (loss) from discontinued operations in 2011 primarily reflects the results of operations of our former exploration and production business as discontinued operations following the spin-off of WPX. See Note 4 – Discontinued Operations of Notes to Consolidated Financial Statements for a more detailed discussion of the items in Income (loss) from discontinued operations.

The favorable change in Net income attributable to noncontrolling interests primarily reflects lower operating results at WPZ and higher income allocated to the general partner driven by incentive distribution rights, partially offset by our decreased percentage of limited partner ownership of WPZ, which was 68 percent at December 31, 2012, compared to 73 percent at December 31, 2011.

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Year-Over-Year Operating Results – Segments

Williams Partners

	Years Ended December 31,
	2013		2012		2011
	(Millions)
Segment revenues	$	6,685	$	7,320	$	7,714
Segment costs and expenses	(5,183)		(5,619)		(5,821)
Equity earnings (losses)	104		111		142
Segment profit	$	1,606	$	1,812	$	2,035

2013 vs. 2012

The decrease in segment revenues includes:

• A $348 million decrease in revenues from our equity NGLs including $256 million due to lower volumes and a $92 million decrease associated with 10 percent lower average realized non-ethane per-unit sales prices and 44 percent lower average ethane per-unit sales prices. Equity ethane sales volumes are 81 percent lower driven by unfavorable ethane economics, as previously mentioned, and equity non-ethane volumes are 9 percent lower primarily due to a customer contract that expired in September 2013 and a change in a customer’s contract at the end of 2012 to fee-based processing, along with periods of severe winter weather conditions in the first quarter of 2013 that prevented producers from delivering gas in our western onshore operations.

• A $312 million decrease in olefin sales due to $363 million associated with lower volumes, partially offset by $51 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, an outage in a third-party storage facility which caused us to reduce production at our RGP splitter facility, and changes in inventory management. Ethylene and propylene prices averaged 21 percent and 11 percent higher, respectively, partially offset by 29 percent lower butadiene prices.

• A $229 million decrease in marketing revenues primarily due to $244 million associated with lower NGL prices and $136 million associated with lower crude oil volumes, partially offset by $130 million related to higher non-ethane volumes primarily related to new marketing activity in our Ohio Valley Midstream business. The changes in marketing revenues are more than offset by similar changes in marketing purchases.

• A $201 million increase in service revenues primarily includes $167 million higher fee revenues resulting from higher gathering volumes driven by new well connections related to infrastructure additions placed into service in 2012 and 2013, a full year of operations associated with gathering systems included in the 2012 acquisitions, 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 $106 million primarily due to 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 $43 million decrease in gathering and processing revenues primarily due to a natural decline in production volumes, primarily in the Piceance basin and Four Corners area, 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 $34 million in the eastern Gulf Coast primarily driven by natural declines in Bass Lite and Blind Faith production area volumes.

• A $53 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).

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The decrease in segment costs and expenses includes:

• A $256 million decrease in marketing purchases primarily due to lower NGL prices and lower crude oil volumes, partially offset by higher non-ethane volumes (substantially offset in marketing revenues).

• A $220 million decrease in olefin feedstock purchases due to $207 million associated with lower volumes, primarily due to the loss of production as a result of the Geismar Incident and the third-party storage facility outage discussed above, and $13 million lower feedstock costs, reflecting 21 percent lower average per-unit ethylene feedstock costs, partially offset by 11 percent higher average per-unit propylene feedstock costs.

• A $51 million decrease in costs associated with our equity NGLs reflecting a $102 million decrease due to lower natural gas volumes driven by lower ethane recoveries, partially offset by a $51 million increase related to a 32 percent increase in average natural gas prices.

• A $50 million increase in operating costs includes $42 million in higher Operating and maintenance 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, as well as $13 million of costs incurred under our insurance deductibles associated with the Geismar Incident. These increases are partially offset by lower compressor and pipeline maintenance and repair expenses at our Gulf Coast businesses primarily due to the absence of expenses relating to the substantial completion of a natural gas pipeline integrity management plan during 2012. Additionally, the increase in operating costs includes $44 million in higher Depreciation and amortization expenses primarily reflecting a full year of 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. Partially offsetting these increases in operating costs is lower SG&A primarily due to the absence of acquisition and transition costs of $23 million incurred in 2012.

• A $50 million increase in other product costs primarily due to higher system management gas costs from our gas pipeline businesses (offset in segment revenues).

• An $8 million favorable change in Other (income) expense - net primarily attributable to the recognition of $40 million of income associated with the net insurance recoveries related to the Geismar Incident during 2013 and $9 million involuntary conversion gains related to a 2012 furnace fire at our Geismar olefins plant. The favorable changes are partially offset by a $25 million accrued loss for a settlement in principle of a producer claim against us and $23 million higher amortization of regulatory assets associated with asset retirement obligations in 2013.

The decrease in segment profit includes:

• A $297 million decrease in NGL margins driven primarily by lower NGL volumes and prices and higher natural gas prices, partially offset by lower natural gas volumes.

• A $92 million decrease in olefin margins including $156 million associated with lower product volumes at our Geismar plant offset by $41 million higher ethylene per-unit sales prices and $21 million lower ethylene feedstock costs.

• A $50 million increase in operating costs as previously discussed.

• A $7 million decrease in Equity earnings (losses) primarily due to $20 million lower equity earnings from Discovery driven by lower NGL margins reflecting lower volumes including reduced ethane recoveries and natural declines, as well as lower NGL prices. In addition, charges to write-down two lateral pipelines and electrical equipment in 2013 and the absence of a favorable customer settlement in 2012 decreased equity earnings from Discovery. The decrease is partially offset by $15 million improved equity earnings from Laurel Mountain driven primarily by 55 percent higher gathering volumes, the receipt of an annual minimum volume commitment fee in 2013, and lower leased compression expenses.

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• A $201 million increase in service revenues as previously discussed.

• A $27 million increase in marketing margins primarily due to favorable prices in 2013 and the absence of losses recognized in the second quarter of 2012 driven by significant declines in NGL prices while product was in transit.

• An $8 million favorable change in Other (income) expense - net as previously discussed.

2012 vs. 2011

The decrease in segment revenues includes:

• A $366 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $354 million associated with an overall 26 percent decrease in average NGL per-unit sales prices. Average ethane and non-ethane per-unit prices decreased by 49 percent and 15 percent, respectively.

• A $77 million decrease in olefin sales revenues including $42 million lower ethylene production sales revenues primarily due to 10 percent lower average per-unit sales prices and $26 million lower propylene production sales revenues primarily due to 17 percent lower average per-unit sales prices.

• Marketing revenues were $93 million lower primarily due to a significant decrease in NGL and olefin prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities.

• A $39 million decrease in system management gas sales from our gas pipeline businesses (offset in segment costs and expenses).

• A $203 million increase in fee revenues primarily includes $163 million higher fee revenues due to higher volumes in the Marcellus Shale, including new volumes on our gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses; higher volumes in the western deepwater Gulf of Mexico, including higher volumes on our Perdido Norte natural gas and oil pipelines; and higher volumes in the Piceance basin. It also includes a $40 million increase in transportation revenues associated with natural gas pipeline expansion projects placed in service during 2011 and 2012.

The decrease in segment costs and expenses includes:

• A $183 million decrease in olefin feedstock costs including $130 million lower ethylene feedstock costs driven by 38 percent lower average per-unit feedstock costs and $28 million lower propylene feedstock costs primarily due to 20 percent lower per-unit feedstock costs.

• A $137 million decrease in costs associated with our equity NGLs primarily due to a 31 percent decrease in average natural gas prices.

• A $39 million decrease in system management gas costs from our gas pipeline businesses (offset in segment revenues).

• A $46 million decrease in marketing purchases primarily due to significantly lower average NGL prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities. The changes in natural gas marketing purchases are more than offset by similar changes in natural gas marketing revenues.

• A $132 million increase in operating costs including higher depreciation and amortization of assets and intangibles, along with maintenance costs associated with assets acquired in 2012, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.

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• An $81 million increase in general and administrative expenses including $23 million of Caiman and Laser acquisition and transition-related costs, as well as increases in employee-related and information technology expenses driven by general growth within our business operations.

The decrease in segment profit includes:

• A $229 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices.

• A $132 million increase in operating costs as previously discussed.

• An $81 million increase in general and administrative expenses as previously discussed.

• A $47 million decrease in margins related to the marketing of NGLs primarily due to the impact of a significant and rapid decline in NGL prices, primarily during the second quarter of 2012, while product was in transit and a $7 million unfavorable change in write-downs of inventories to lower of cost or market. These unfavorable variances compare to periods of increasing prices during 2011.

• A $31 million decrease in Equity earnings (losses) primarily due to $19 million lower Laurel Mountain equity earnings driven by lower gathering rates indexed to natural gas prices, higher operating costs, including depreciation, and the impairment of two minor NGL processing plants, partially offset by higher gathered volumes; $12 million lower Aux Sable equity earnings primarily due to lower NGL margins; and $12 million lower Discovery equity earnings primarily due to lower NGL margins and volumes. These decreases are partially offset by $11 million higher Gulfstream equity earnings primarily due to WPZ’s acquisition of additional interest in Gulfstream, which was previously reflected in Other.

• A $203 million increase in fee revenues as previously discussed.

• A $106 million increase in olefin product margins including $88 million higher ethylene production margins primarily due to 38 percent lower average per-unit feedstock prices, partially offset by 10 percent lower average per-unit sales prices. DAC production margins were also $13 million higher, primarily resulting from higher average per-unit margins driven primarily by lower average per-unit feedstock prices.

Williams NGL & Petchem Services

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Segment revenues	$	273		$	279		$	341
Segment costs and expenses	(235		)	(180		)	(184		)
Segment profit	$	38		$	99		$	157

2013 vs. 2012

Segment revenues decreased primarily due to $7 million lower propylene product sales revenues primarily due to 23 percent lower sales volumes partially offset by 18 percent higher average per-unit sales prices. The lower sales volumes were due to a scheduled third-quarter 2013 shutdown to conduct maintenance and to effect the ethane recovery project tie-in, as well as the impact of delays associated with resuming production during the fourth quarter of 2013. These decreased volumes were partially offset by the absence of the impact of filling the Boreal Pipeline in June 2012.

Segment costs and expenses increased $55 million primarily due to $23 million higher Operating and maintenance expenses primarily resulting from increased maintenance related to the scheduled third-quarter 2013 shutdown, as well as a $16 million unfavorable change in Other (income) expense – net primarily due to the $20 million write-off of an abandoned project, partially offset by the favorable impact of foreign currency exchange. Additionally, Depreciation and amortization expenses increased $13 million primarily due to certain assets that were decommissioned in the third

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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.

Segment profit decreased primarily due to $23 million higher Operating and maintenance expenses, a $20 million write-off of an abandoned project and $13 million higher Depreciation and amortization expenses, as previously discussed. Additionally, propylene margins decreased $7 million due to 23 percent lower sales volumes partially offset by 16 percent higher average per-unit sales prices.

2012 vs. 2011

Segment revenues decreased primarily due to $53 million lower NGL product sales revenues primarily due to 22 percent lower average per-unit sales prices. Additionally, propylene product sales revenues decreased $12 million primarily due to 22 percent lower average per-unit sales prices, partially offset by 10 percent higher sales volumes.

Segment costs and expenses decreased $4 million primarily as a result of $23 million lower NGL feedstock costs resulting from 25 percent lower average per-unit feedstock costs; substantially offset by the absence of $19 million of income related to the reduction of our accrual for the Gulf Liquids litigation in 2011 (See Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements.)

Segment profit decreased primarily due to $30 million lower NGL product margins primarily due to 20 percent lower average per-unit margins and $12 million lower propylene product margins primarily due to 24 percent lower average per-unit margins on higher sales volumes. Also contributing to the decrease is the absence of $19 million of income related to the reduction of our accrual for the Gulf Liquids litigation in 2011.

Access Midstream Partners

	Years Ended December 31,
	2013		2012		2011
	(Millions)
Segment profit	$	61	$	—	$	—

2013 vs. 2012

Segment profit in 2013 includes $93 million of equity earnings recognized from Access Midstream Partners, which we acquired an interest in during December 2012. Offsetting the 2013 equity earnings is $63 million of 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 noncash gains of $31 million resulting from Access Midstream Partners’ equity issuances in 2013. These equity issuances resulted in the dilution of our ownership of limited partnership units 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 from Access Midstream Partners totaling $93 million.

Other

	Years Ended December 31,
	2013			2012		2011
	(Millions)
Segment revenues	$	36		$	27	$	25
Segment profit (loss)	(4		)	49		24

2013 vs. 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 5 –

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Investing Activities of Notes to Consolidated Financial Statements.) The unfavorable change also reflects $6 million of project development costs incurred in the first quarter of 2013.

2012 vs. 2011

The favorable change in segment profit is primarily due to $42 million of increased gains recognized related to the 2010 sale of our interest in Accroven SRL. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.) The favorable change is partially offset by $12 million decreased equity earnings due to the contribution of a 24.5 percent interest in Gulfstream to WPZ in May 2011.

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Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview

In 2013, we continued to focus upon both growth in our businesses through disciplined investment and growth in our per-share dividends. Examples of this growth included:

• Expansion of Williams Partners’ interstate natural gas pipeline system to meet the demand of growth markets;

• Continued investment in Williams Partners’ gathering and processing capacity and infrastructure in the Marcellus Shale area and deepwater Gulf of Mexico, as well as expansion of our olefins business in the Gulf Coast region;

• Expansion of our Canadian facilities and investment in a joint project to develop the Bluegrass Pipeline;

• Total per-share dividends grew 20 percent to $1.4375 in 2013 compared to $1.19625 in 2012.

This growth was funded through cash flow from operations, distributions from WPZ and Access Midstream Partners, debt and equity offerings at WPZ, and cash on hand.

Outlook

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

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

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

We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, dividends and distributions, debt service payments, and tax payments, including an estimated $111 million tax payment as a result of WPZ’s expected acquisition of certain of our Canadian operations, while maintaining a sufficient level of liquidity. In particular, we note the following:

• We expect capital and investment expenditures to total between $4.16 billion and $5.04 billion in 2014. Of this total, maintenance capital expenditures, which are generally considered nondiscretionary and include expenditures to meet legal and regulatory requirements, to maintain and/or extend the operating capacity and useful lives of our assets, and to complete certain well connections, are expected to total between $360 million and $440 million. Expansion capital expenditures, which are generally more discretionary to fund projects in order to grow our business are expected to total between $3.8 billion and $4.6 billion. See Company Outlook - Expansion Projects for discussions describing the general nature of these expenditures. In addition, we retain the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

• We expect to pay total cash dividends of approximately $1.75 per common share in 2014, an increase of 22 percent over 2013 levels.

• We expect to fund working capital requirements, capital and investment expenditures, debt service payments, dividends and distributions, and tax payments primarily through cash flow from operations, cash and cash equivalents on hand, issuances of WPZ debt and/or equity securities, and utilization of our credit facility and WPZ’s credit facility and/or commercial paper program. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $2.85 billion and $3.175 billion in 2014.

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Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2014. Our internal and external sources of consolidated liquidity include cash generated from our operations, including cash distributions from WPZ and our equity method investments based on our level of ownership and incentive distribution rights, cash and cash equivalents on hand, cash proceeds from WPZ’s offerings of common units, our credit facility and WPZ’s credit facility 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 credit facility and/or commercial paper program, and its access to capital markets.

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

As of December 31, 2013, we had a working capital deficit (current liabilities, inclusive of commercial paper borrowings, in excess of current assets) of $300 million. However, we note the following about our available liquidity.

	December 31, 2013
Available Liquidity	WPZ		WMB			Total
	(Millions)
Cash and cash equivalents	$	102	$	579	(1)	$	681
Capacity available under our $1.5 billion credit facility (expires July 31, 2018) (2)			1,500			1,500
Capacity available to WPZ under its $2.5 billion five-year credit facility (expires July 31, 2018) less amounts outstanding under its $2 billion commercial paper program (3)(4)	2,275					2,275
	$	2,377	$	2,079		$	4,456

__________

(1) Includes $278 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. The remainder of our Cash and cash equivalents is primarily held in government-backed instruments.

(2) We did not borrow on our credit facility during 2013. At December 31, 2013, we are in compliance with the financial covenants associated with this credit facility. (See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.) On July 31, 2013, we amended our $900 million credit facility to increase the aggregate commitments to $1.5 billion and extend the maturity date to July 31, 2018. The amended credit facility, under certain circumstances, may be increased up to an additional $500 million.

(3) The highest amount outstanding during 2013 was $1.085 billion under WPZ’s commercial paper program. As of February 25, 2014, $900 million is outstanding under WPZ’s commercial paper program. At December 31, 2013, WPZ is in compliance with the financial covenants associated with the credit facility and commercial paper program. (See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.) The WPZ credit facility is only available to WPZ, Transco, and Northwest Pipeline as co-borrowers. On July 31, 2013, WPZ amended its $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. The amended credit facility, 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 credit facility.

In addition to the credit facilities and WPZ’s commercial paper program listed above, we have issued letters of credit totaling $16 million as of December 31, 2013, under certain bilateral bank agreements.

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As described in Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements, we have determined that we have net assets that are technically considered restricted in accordance with Rule 4-08(e) of Regulation S-X of the Securities and Exchange Commission in excess of 25 percent of our consolidated net assets. We do not expect this determination will impact our ability to pay dividends or meet future obligations as the terms of WPZ’s partnership agreement require it to make quarterly distributions of all available cash, as defined, to its unitholders.

Commercial Paper

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. WPZ classifies these commercial paper notes outstanding as short-term borrowings as they have maturity dates less than three months from the date of issuance. At December 31, 2013, WPZ had $225 million in commercial paper outstanding.

Debt Offering

In November 2013, WPZ completed a public offering of $600 million of 4.5 percent senior unsecured notes due 2023 and $400 million of 5.8 percent senior unsecured notes due 2043. WPZ used the net proceeds to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes.

Distributions from Equity Method Investees

Our equity-method investees’ organizational documents require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. Our more significant equity-method investees include: Access Midstream Partners, Aux Sable, Caiman II, Discovery, Gulfstream, Laurel Mountain, and OPPL.

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 December 31, 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 credit facility.

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

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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 February 2014 distribution were reduced by a total of $147 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. Cash distributions to us from WPZ through the February 2014 distribution were reduced by a total of $90 million in association with these waived incentive distributions.

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 December 31, 2013, we estimate that a downgrade to a rating below investment grade for us or WPZ could require us to post up to $8 million or $282 million, respectively, in additional collateral with third parties.

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Sources (Uses) of Cash

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Net cash provided (used) by:
Operating activities	$	2,217		$	1,835		$	3,439
Financing activities	1,677			5,036			(342		)
Investing activities	(4,052		)	(6,921		)	(3,003		)
Increase (decrease) in cash and cash equivalents	$	(158	)	$	(50	)	$	94

Operating activities

The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash expenses such as Depreciation, depletion, and amortization, Provision (benefit) for deferred income taxes, and Gain on reconsolidation of Wilpro entities. Our Net cash provided by operating activities in 2013 increased from 2012 primarily due to proceeds from insurance recoveries on the Eminence Storage Field leak and Geismar Incident, $93 million of distributions from our investment in Access Midstream Partners acquired in December 2012, and net favorable changes in operating working capital, partially offset by lower operating income.

Our Net cash provided by operating activities in 2012 decreased from 2011 primarily due to the absence of cash flows from our former exploration and production business and lower operating results.

Financing activities

Significant transactions include:

2013

• $224 million net proceeds received from WPZ’s commercial paper issuances;

• $1.705 billion received from WPZ’s credit facility borrowings:

• $994 million net proceeds received from WPZ’s November 2013 public offering of $600 million of 4.5 percent senior unsecured notes due 2023 and $400 million of 5.8 percent senior unsecured notes due 2043;

• $2.08 billion paid on WPZ’s credit facility borrowings;

• $1.819 billion received from WPZ’s equity offerings;

• $982 million paid for quarterly dividends on common stock for the year ended December 31, 2013;

• $489 million paid for dividends and distributions to noncontrolling interests;

• $467 million received in contributions from noncontrolling interests.

2012

• $2.5 billion net proceeds received from our 2012 equity offerings;

• $1.559 billion received from WPZ’s 2012 equity offerings;

• $842 million net proceeds received from our December 2012 public offering of $850 million of 3.7 percent senior unsecured notes due 2023;

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• $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;

• $1.49 billion received from WPZ’s credit facility borrowings;

• $1.115 billion of WPZ’s credit facility borrowings paid;

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

• We paid $742 million of quarterly dividends on common stock for the year ended December 31, 2012;

• We paid $387 million of dividends and distributions to noncontrolling interests.

2011

• $526 million of cash retained by WPX upon spin-off on December 31, 2011;

• $746 million of notes and debentures retired in December 2011 and $254 million paid in associated premiums;

• $1.5 billion received from WPX’s issuance of senior unsecured notes in November 2011;

• $500 million received from WPZ’s public offering of senior unsecured notes in November 2011 primarily used to repay borrowings on its credit facility mentioned below;

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

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

• $300 million received in borrowings from WPZ’s $1.75 billion unsecured credit facility;

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

• We paid $457 million of quarterly dividends on common stock for the year ended December 31, 2011;

• $425 million in net borrowings and payments related to WPZ’s credit facility;

• We paid $214 million of dividends and distributions to noncontrolling interests.

Investing activities

Significant transactions include:

2013

• Capital expenditures totaled $3.572 billion for 2013;

• Purchases of and contributions to our equity method investments of $455 million.

2012

• Capital expenditures totaled $2.529 billion for 2012;

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• Purchases of and contributions to our equity method investments of $2.7 billion, including $2.19 billion paid in December 2012 for our investment in Access Midstream Partners;

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

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

• $121 million received from the reconsolidation of the Wilpro entities (see Note 4 – Discontinued Operations of our Notes to Consolidated Financial Statements).

2011

• Capital expenditures totaled $2.796 billion in 2011;

• We contributed $137 million to our Laurel Mountain equity investment.

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

We have various other guarantees and commitments which are disclosed in Note 3 – Variable Interest Entities, Note 11 – Property, Plant, and Equipment, Note 13 – Debt, Banking Arrangements, and Leases, Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk, and Note 17 – Contingent Liabilities and Commitments 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.

Contractual Obligations

The table below summarizes the maturity dates of our contractual obligations at December 31, 2013:

	2014		2015 - 2016		2017 - 2018		Thereafter		Total
					(Millions)
Long-term debt:
Principal	$	—	$	1,125	$	1,285	$	8,980	$	11,390
Interest	624		1,182		1,026		5,008		7,840
Commercial paper	225		—		—		—		225
Capital leases	1		—		—		—		1
Operating leases (1)	54		91		66		123		334
Purchase obligations (2)	2,055		519		440		938		3,952
Other obligations (3)(4)	2		2		—		—		4
Total	$	2,961	$	2,919	$	2,817	$	15,049	$	23,746

__________

(1) Includes a right-of-way agreement with the Jicarilla Apache Nation. We are required to make a fixed annual payment of $8 million and an additional annual payment, which varies depending on per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the right-of-way agreement. The table above for years 2015 and thereafter does not include such variable amounts related to this agreement as the variable amount is not yet determinable. The variable portion to be paid in 2014 based on 2013 gathering volumes is $5 million and is included in the table for year 2014.

(2) Includes approximately $1.2 billion in open property, plant and equipment purchase orders. Larger projects include Gulfstar One and the Oak Grove plant.Includes an estimated $621 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2013 prices. This obligation is part of an overall exchange agreement whereby volumes we transport on OPPL are sold at a third-party fractionator

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near Conway, Kansas, and we are subsequently obligated to purchase ethane volumes at Mont Belvieu. The purchased ethane volumes may be utilized or resold at comparable prices in the Mont Belvieu market. Includes an estimated $953 million long-term NGL purchase obligation with index-based pricing terms that primarily supplies a third party at its plant and is valued in this table at a price calculated using December 31, 2013 prices. Any excess purchased volumes may be sold at comparable market prices. In addition, we have not included certain natural gas life-of-lease contracts for which the future volumes are indeterminable. We have not included commitments, beyond purchase orders, for the acquisition or construction of property, plant and equipment or expected contributions to our jointly owned investments (See Company Outlook — Expansion Projects).

(3) Does not include estimated contributions to our pension and other postretirement benefit plans. We made contributions to our pension and other postretirement benefit plans of $100 million in 2013 and $92 million in 2012. In 2014, we expect to contribute approximately $71 million to these plans (see Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements). Tax-qualified pension plans are required to meet minimum contribution requirements. In the past, we have contributed amounts to our tax-qualified pension plans in excess of the minimum required contribution. These excess amounts can be used to offset future minimum contribution requirements. During 2013, we contributed $90 million to our tax-qualified pension plans. In addition to these contributions, a portion of the excess contributions was used to meet the minimum contribution requirements. During 2014, we expect to contribute approximately $60 million to our tax-qualified pension plans and use excess amounts to satisfy minimum contribution requirements, if needed. Additionally, estimated future minimum funding requirements may vary significantly from historical requirements if actual results differ significantly from estimated results for assumptions such as returns on plan assets, interest rates, retirement rates, mortality, and other significant assumptions or by changes to current legislation and regulations.

(4) We have not included income tax liabilities in the table above. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of income taxes, including our contingent tax liability reserves.

Effects of Inflation

Our operations have historically not been materially affected by inflation. Approximately 47 percent of our gross property, plant, and equipment is comprised of our interstate natural gas pipeline assets. They are subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to replace existing assets. Cost-based regulations, along with competition and other market factors, may limit our ability to recover such increased costs. For our gathering and processing assets, operating costs are influenced to a greater extent by both competition for specialized services and specific price changes in crude oil and natural gas and related commodities than by changes in general inflation. Crude oil, natural gas, and NGL prices are particularly sensitive to the Organization of the Petroleum Exporting Countries (OPEC) production levels and/or the market perceptions concerning the supply and demand balance in the near future, as well as general economic conditions. However, our exposure to certain of these price changes is reduced through the fee-based nature of certain of our services and the use of hedging instruments.

Environmental

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and/or remedial processes at certain sites, some of which we currently do not own (see Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $47 million, all of which are included in Accrued liabilities and Other noncurrent liabilities on the Consolidated Balance Sheet at December 31, 2013. We will seek recovery of approximately $13 million of these accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2013, we paid approximately$16 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $13 million in 2014 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results

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of studies or our experience with other similar cleanup operations. At December 31, 2013, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground level ozone to ensure that the standards were clearly grounded in science and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone nonattainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. In September 2011, the EPA announced that it was proceeding with required actions to implement the 2008 ozone standard and area designations. In May 2012, the EPA completed designation of new eight-hour ozone nonattainment areas. Several Transco facilities are located in 2008 ozone nonattainment areas; however, each facility has been previously subjected to federal and/or state emission control requirements implemented to address the preceding ozone standards. To date, no new federal or state actions have been proposed to mandate additional emission controls at these facilities. At this time, it is unknown whether future federal or state regulatory actions associated with implementation of the 2008 ozone standard will impact our operations and increase the cost of additions to Property, plant and equipment – net on the Consolidated Balance Sheet. Until any additional federal or state regulatory actions are proposed, we are unable to estimate the cost of additions that may be required to meet this new regulation. Additionally, several nonattainment areas exist in or near areas where we have operating assets. States are required to develop implementation plans to bring these areas into compliance. Implementing regulations are expected to result in impacts to our operations and increase the cost of additions to Property, plant and equipment – net on the Consolidated Balance Sheet for both new and existing facilities in affected areas.

In June 2010, the EPA promulgated a final rule establishing a new one-hour sulfur dioxide (SO2) NAAQS. The effective date of the new SO2 standard was August 23, 2010. The EPA has not adopted final modeling guidance. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.

On January 22, 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. This standard is subject to challenge in federal court. On January 20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO2 NAAQS and thus designated all areas of the country as “unclassifiable/attainment.” Also, at that time the EPA noted its plan to deploy an expanded NO2 monitoring network beginning in 2013. However on October 5, 2012, the EPA proposed a graduated implementation of the monitoring network between January 1, 2014 and January 1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO2 NAAQS. Until that time, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 standard. Because we are unable to predict the outcome of the EPA’s or states’ future assessment using the new monitoring network, we are unable to estimate the cost of additions that may be required to meet this regulation.

Our interstate natural gas pipelines consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio is primarily comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Any borrowings under our credit facilities and any issuances under WPZ’s commercial paper program could be at a variable interest rate and could expose us to the risk of increasing interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected lives of our operating assets.  (See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)

The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December 31, 2013 and 2012. Long-term debt in the tables represents principal cash flows, net of (discount) premium, and weighted-average interest rates by expected maturity dates. The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings.

		2014			2015			2016			2017			2018			Thereafter (1)			Total		Fair Value December 31, 2013
	(Millions)
Long-term debt, including current portion: (2)
Fixed rate	$	—		$	750		$	375		$	785		$	500		$	8,943		$	11,353	$	11,971
Interest rate		5.5	%		5.6	%		5.6	%		5.5	%		5.4	%		6.0	%
Variable rate (3)	$	225		$	—		$	—		$	—		$	—		$	—		$	225	$	225
Interest rate (4)
		2013			2014			2015			2016			2017			Thereafter (1)			Total		Fair Value December 31, 2012
	(Millions)
Long-term debt, including current portion: (2)
Fixed rate	$	—		$	—		$	750		$	375		$	785		$	8,449		$	10,359	$	12,013
Interest rate		5.5	%		5.5	%		5.6	%		5.7	%		5.6	%		6.0	%
Variable rate	$	—		$	—		$	—		$	375		$	—		$	—		$	375	$	375
Interest rate (4)

__________________

(1) Includes unamortized discount and premium.

(2) Excludes capital leases.

(3) Consists of Commercial paper.

(4) The weighted average interest rate was 0.42 percent and 2.7 percent at December 31, 2013 and 2012, respectively.

Commodity Price Risk

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

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December 31, 2013 and 2012, our derivative activity was not material. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)

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 $1.12 billion and $899 million at December 31, 2013 and 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$224 million at December 31, 2013.

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Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of

The Williams Companies, Inc.

We have audited the accompanying consolidated balance sheet of The Williams Companies, Inc. as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2013. Our audits also included the financial statement schedules listed in the index at Item 15(a). These financial statements and schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits. We did not audit the financial statements of Gulfstream Natural Gas System, L.L.C. (“Gulfstream”) (a limited liability corporation in which the Company has a 50 percent interest) or Access Midstream Partners, L.P. (“ACMP”) (a publicly traded master limited partnership in which the Company has a 50 percent general partner interest and a 23 percent limited partner interest). The Company’s investment in Gulfstream constituted one percent of the Company’s assets as of each of December 31, 2013 and 2012, and the Company’s equity earnings in the net income of Gulfstream constituted six, five, and five percent, respectively, of the Company’s income from continuing operations before income taxes for each of the three years in the period ended December 31, 2013. The Company’s investment in ACMP constituted eight percent of the Company’s assets as of December 31, 2013, and the Company’s equity earnings in the net income of ACMP constituted nine percent of the Company’s income from continuing operations before income taxes for the year ended December 31, 2013. Gulfstream’s and ACMP’s financial statements for the periods indicated above were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Gulfstream and ACMP for these periods, is based solely on the reports of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the reports of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of The Williams Companies, Inc. at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), The Williams Companies, Inc.’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 26, 2014, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 26, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of Gulfstream Natural Gas System, L.L.C.

We have audited the balance sheets of Gulfstream Natural Gas System, L.L.C., (the "Company") as of December 31, 2013 and 2012, and the related statements of operations, comprehensive income, members' equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream Natural Gas System, L.L.C. as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

February 24, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Access Midstream Partners GP, L.L.C., as General Partner of Access Midstream Partners, L.P. and the Unitholders:

In our opinion, the consolidated balance sheet of Access Midstream Partners, L.P. as of December 31, 2013, and the related consolidated statements of operations, of changes in partners’ capital and of cash flows for the year then ended (not presented herein) present fairly, in all material respects, the financial position of Access Midstream Partners, L.P. and its subsidiaries (the “Partnership) as of December 31, 2013, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

February 21, 2014

79

The Williams Companies, Inc.

Consolidated Statement of Income

		Years Ended December 31,
		2013			2012			2011
	(Millions, except per-share amounts)
Revenues:
Service revenues		$	2,939		$	2,729		$	2,532
Product sales		3,921			4,757			5,398
Total revenues		6,860			7,486			7,930
Costs and expenses:
Product costs		3,027			3,496			3,934
Operating and maintenance expenses		1,097			1,027			990
Depreciation and amortization expenses		815			756			661
Selling, general, and administrative expenses		512			571			477
Other (income) expense – net		34			24			1
Total costs and expenses		5,485			5,874			6,063
Operating income (loss)		1,375			1,612			1,867
Equity earnings (losses)		134			111			155
Interest incurred		(611		)	(568		)	(598		)
Interest capitalized		101			59			25
Other investing income – net		81			77			13
Early debt retirement costs		—			—			(271		)
Other income (expense) – net		—			(2		)	11
Income (loss) from continuing operations before income taxes		1,080			1,289			1,202
Provision (benefit) for income taxes		401			360			124
Income (loss) from continuing operations		679			929			1,078
Income (loss) from discontinued operations		(11		)	136			(417		)
Net income (loss)		668			1,065			661
Less: Net income attributable to noncontrolling interests		238			206			285
Net income (loss) attributable to The Williams Companies, Inc.		$	430		$	859		$	376
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations		$	441		$	723		$	803
Income (loss) from discontinued operations		(11		)	136			(427		)
Net income (loss)		$	430		$	859		$	376
Basic earnings (loss) per common share:
Income (loss) from continuing operations		$	.65		$	1.17		$	1.36
Income (loss) from discontinued operations		(.02		)	.22			(.72		)
Net income (loss)		$	.63		$	1.39		$	.64
Weighted-average shares (thousands)		682,948			619,792			588,553
Diluted earnings (loss) per common share:
Income (loss) from continuing operations		$	.64		$	1.15		$	1.34
Income (loss) from discontinued operations		(.02		)	.22			(.71		)
Net income (loss)		$	.62		$	1.37		$	.63
Weighted-average shares (thousands)		687,185			625,486			598,175

See accompanying notes.

80

The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Net income (loss)	$	668		$	1,065		$	661
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of ($7) and ($152) in 2012 and 2011, respectively	1			22			243
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $7 and $124 in 2012 and 2011, respectively	(1		)	(23		)	(190		)
Foreign currency translation adjustments, net of taxes of $24 in 2013	(41		)	22			(18		)
Pension and other postretirement benefits:
Prior service credit arising during the year, net of taxes of ($9), ($1) and ($1) in 2013, 2012 and 2011, respectively (Note 9)	14			1			1
Amortization of prior service cost (credit) included in net periodic benefit cost, net of taxes of $1 in 2013, 2012, and 2011	(2		)	(1		)	(2		)
Net actuarial gain (loss) arising during the year, net of taxes of ($111), $19 and $89 in 2013, 2012 and 2011, respectively (Note 9)	189			(30		)	(152		)
Amortization of actuarial (gain) loss included in net periodic benefit cost, net of taxes of ($23), ($22) and ($16) in 2013, 2012 and 2011, respectively	38			39			27
Equity Securities:
Unrealized gain (loss) on equity securities, net of taxes of ($2) in 2011	—			—			3
Reclassifications into earnings of (gain) loss on sale of equity securities, net of taxes of $2 in 2012	—			(3		)	—
Other comprehensive income (loss)	198			27			(88		)
Comprehensive income (loss)	866			1,092			573
Less: Comprehensive income (loss) attributable to noncontrolling interests	238			206			285
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	628		$	886		$	288

See accompanying notes.

81

The Williams Companies, Inc.

Consolidated Balance Sheet

	December 31,
	2013			2012
	(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	681		$	839
Accounts and notes receivable, net:
Trade and other	600			620
Income tax receivable	74			68
Deferred income tax asset	27			117
Inventories	194			175
Other current assets and deferred charges	107			105
Total current assets	1,683			1,924
Investments	4,360			3,987
Property, plant, and equipment – net	18,210			15,467
Goodwill	646			649
Other intangible assets	1,644			1,704
Regulatory assets, deferred charges, and other	599			596
Total assets	$	27,142		$	24,327
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	960		$	920
Accrued liabilities	797			628
Commercial paper	225			—
Long-term debt due within one year	1			1
Total current liabilities	1,983			1,549
Long-term debt	11,353			10,735
Deferred income taxes	3,529			2,841
Other noncurrent liabilities	1,356			1,775
Contingent liabilities and commitments (Note 17)
Equity:
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 718 million shares issued at December 31, 2013 and 716 million shares issued at December 31, 2012)	718			716
Capital in excess of par value	11,599			11,134
Retained deficit	(6,248		)	(5,695		)
Accumulated other comprehensive income (loss)	(164		)	(362		)
Treasury stock, at cost (35 million shares of common stock)	(1,041		)	(1,041		)
Total stockholders’ equity	4,864			4,752
Noncontrolling interests in consolidated subsidiaries	4,057			2,675
Total equity	8,921			7,427
Total liabilities and equity	$	27,142		$	24,327

See accompanying notes.

82

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity

	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 Interests			Total
	(Millions)
Balance – December 31, 2010	$	620	$	7,784	$	(478	)	$	(82	)	$	(1,041	)	$	6,803		$	1,331		$	8,134
Net income (loss)	—		—		376			—			—			376			285			661
Other comprehensive income (loss)	—		—		—			(88		)	—			(88		)	—			(88		)
Cash dividends – common stock (Note 14)	—		—		(457		)	—			—			(457		)	—			(457		)
Dividends and distributions to noncontrolling interests	—		—		—			—			—			—			(214		)	(214		)
Issuance of common stock from debentures conversion	1		13		—			—			—			14			—			14
Stock-based compensation and related common stock issuances, net of tax	4		104		—			—			—			108			—			108
Changes in Williams Partners L.P. ownership interests, net	—		18		—			—			—			18			(30		)	(12		)
Distribution of WPX Energy, Inc. to stockholders (Note 4)	—		—		(5,261		)	(219		)	—			(5,480		)	(81		)	(5,561		)
Other	1		1		—			—			—			2			(1		)	1
Balance – December 31, 2011	626		7,920		(5,820		)	(389		)	(1,041		)	1,296			1,290			2,586
Net income (loss)	—		—		859			—			—			859			206			1,065
Other comprehensive income (loss)	—		—		—			27			—			27			—			27
Cash dividends – common stock (Note 14)	—		—		(742		)	—			—			(742		)	—			(742		)
Dividends and distributions to noncontrolling interests	—		—		—			—			—			—			(387		)	(387		)
Issuance of common stock from debentures conversion	1		5		—			—			—			6			—			6
Stock-based compensation and related common stock issuances, net of tax	6		98		—			—			—			104			—			104
Sales of limited partner units of Williams Partners L.P.	—		—		—			—			—			—			1,559			1,559
Issuances of limited partner units of Williams Partners L.P. related to acquisitions	—		—		—			—			—			—			1,044			1,044
Changes in Williams Partners L.P. ownership interest, net	—		699		—			—			—			699			(1,115		)	(416		)
Sales of common stock (Note 14)	83		2,412		—			—			—			2,495			—			2,495
Reconsolidation of noncontrolling interest in Wilpro entities (Note 4)	—		—		—			—			—			—			65			65
Contributions from noncontrolling interest	—		—		—			—			—			—			14			14
Other	—		—		8			—			—			8			(1		)	7
Balance – December 31, 2012	716		11,134		(5,695		)	(362		)	(1,041		)	4,752			2,675			7,427
Net income (loss)	—		—		430			—			—			430			238			668
Other comprehensive income (loss)	—		—		—			198			—			198			—			198
Cash dividends – common stock (Note 14)	—		—		(982		)	—			—			(982		)	—			(982		)
Dividends and distributions to noncontrolling interests	—		—		—			—			—			—			(489		)	(489		)
Issuance of common stock from debentures conversion	—		1		—			—			—			1			—			1
Stock-based compensation and related common stock issuances, net of tax	2		54		—			—			—			56			—			56
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	—		—		—			—			—			—			467			467
Other	—		1		(1		)	—			—			—			(1		)	(1		)
Balance – December 31, 2013	$	718	$	11,599	$	(6,248	)	$	(164	)	$	(1,041	)	$	4,864		$	4,057		$	8,921

See accompanying notes.

83

The Williams Companies, Inc.

Consolidated Statement of Cash Flows

	Years Ended December 31,
	2013			2012			2011
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	668		$	1,065		$	661
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation, depletion, and amortization	815			756			1,614
Provision (benefit) for deferred income taxes	424			206			(179		)
Provision for loss on investments, property, and other assets	—			—			882
Net (gain) loss on dispositions of assets	28			(52		)	(1		)
Gain on reconsolidation of Wilpro entities (Note 4)	—			(144		)	—
Amortization of stock-based awards	37			36			52
Early debt retirement costs	—			—			271
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable	35			27			(197		)
Inventories	(17		)	5			60
Other current assets and deferred charges	25			29			(15		)
Accounts payable	(35		)	(110		)	250
Accrued liabilities	175			—			51
Other, including changes in noncurrent assets and liabilities	62			17			(10		)
Net cash provided (used) by operating activities	2,217			1,835			3,439
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	224			—			—
Proceeds from long-term debt	2,699			3,486			3,172
Payments of long-term debt	(2,081		)	(1,468		)	(2,055		)
Proceeds from issuance of common stock	18			2,550			49
Proceeds from sale of limited partner units of consolidated partnership	1,819			1,559			—
Dividends paid	(982		)	(742		)	(457		)
Dividends and distributions paid to noncontrolling interests	(489		)	(349		)	(214		)
Distributions paid to noncontrolloing interests on sale of Wilpro assets (Note 4)	—			(38		)	—
Contributions from noncontrolling interests	467			13			—
Cash of WPX Energy, Inc. at spin-off	—			—			(526		)
Premiums paid on early debt retirements	—			—			(254		)
Other – net	2			25			(57		)
Net cash provided (used) by financing activities	1,677			5,036			(342		)
INVESTING ACTIVITIES:
Capital expenditures (1)	(3,572		)	(2,529		)	(2,796		)
Purchases of and contributions to equity method investments	(455		)	(2,651		)	(211		)
Purchases of businesses	(6		)	(2,049		)	(41		)
Proceeds from dispositions of investments	—			79			16
Cash of Wilpro entities upon reconsolidation (Note 4)	—			121			—
Other – net	(19		)	108			29
Net cash provided (used) by investing activities	(4,052		)	(6,921		)	(3,003		)
Increase (decrease) in cash and cash equivalents	(158		)	(50		)	94
Cash and cash equivalents at beginning of year	839			889			795
Cash and cash equivalents at end of year	$	681		$	839		$	889
_________
(1) Increases to property, plant, and equipment	$	(3,653	)	$	(2,755	)	$	(2,953	)
Changes in related accounts payable and accrued liabilities	81			226			157
Capital expenditures	$	(3,572	)	$	(2,529	)	$	(2,796	)

See accompanying notes.

84

The Williams Companies, Inc.

Notes to Consolidated Financial Statements

Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

Description of Business

We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. 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 interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity). WPZ’s midstream operations are composed of significant, large-scale operations in the Rocky Mountain and Gulf Coast regions, operations in the Marcellus Shale region, and various equity investments in domestic natural gas gathering and processing assets and natural gas liquid (NGL) fractionation and transportation assets. WPZ’s midstream assets also include an NGL fractionator and storage facilities near Conway, Kansas, as well as an NGL light-feed olefins cracker in Geismar, Louisiana, along with associated ethane and propane pipelines, 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 interest in Bluegrass Pipeline Company LLC (Bluegrass Pipeline) (a consolidated entity).

Access Midstream Partners consists of our equity investment in Access Midstream Partners, L.P. (ACMP). As of December 31, 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

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 December 31, 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 13 – Debt, Banking Arrangements, and Leases.) 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.

85

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Discontinued operations

On December 31, 2011, we completed the tax-free spin-off of our 100 percent interest in WPX Energy, Inc. (WPX), to our stockholders. The spin-off was completed by means of a special stock dividend, which consisted of a distribution of one share of WPX common stock for every three shares of our common stock. For periods prior to the spin-off, the accompanying Consolidated Statement of Income reflects the results of operations of our former exploration and production business as discontinued operations. The Consolidated Statement of Comprehensive Income and the Consolidated Statement of Cash Flows for 2011 includes the results of our former exploration and production business. (See Note 4 – Discontinued Operations.)

The discontinued operations presented in the accompanying consolidated financial statements and notes reflect gains in 2012 associated with certain of our former Venezuela operations. (See Note 4 – Discontinued Operations.)

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

Related party transaction

A member of our Board of Directors, who was elected in 2013, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded $131 million in Service revenues in the Consolidated Statement of Income from this company for transportation and storage of natural gas for the year ended December 31, 2013. This board member does not have any material interest in any transactions between the energy services company and us and he had no role in any such transactions.

Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of ventures in which we own an undivided interest. Management judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:

• Determining whether an entity is a variable interest entity (VIE);

• Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests;

• Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary;

• Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities.

We apply the equity method of accounting to investments in entities over which we exercise significant influence but do not control.

Equity-method investment basis differences

Differences between the cost of our equity investments and our underlying equity in the net assets of investees are accounted for as if the investees were consolidated subsidiaries. Equity earnings (losses) in the Consolidated Statement of Income includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.

86

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Use of estimates

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.

Significant estimates and assumptions include:

• Impairment assessments of investments, property, plant, and equipment, goodwill, and other identifiable intangible assets;

• Litigation-related contingencies;

• Environmental remediation obligations;

• Realization of deferred income tax assets;

• Depreciation and/or amortization of equity-method investment basis differences;

• Asset retirement obligations;

• Pension and postretirement valuation variables;

• Acquisition related purchase price allocations.

These estimates are discussed further throughout these notes.

Regulatory accounting

Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, our management has determined that it is appropriate to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, and postretirement benefits. Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2013 and 2012 are as follows:

	December 31,
	2013		2012
	(Millions)
Current assets reported within Other current assets and deferred charges	$	39	$	39
Noncurrent assets reported within Regulatory assets, deferred charges, and other	353		366
Total regulated assets	$	392	$	405
Current liabilities reported within Accrued liabilities	$	19	$	15
Noncurrent liabilities reported within Other noncurrent liabilities	329		250
Total regulated liabilities	$	348	$	265

87

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Cash and cash equivalents

Cash and cash equivalents in the Consolidated Balance Sheet includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.

Inventory valuation

All Inventories in the Consolidated Balance Sheet are stated at the lower of cost or market. The cost of inventories is primarily determined using the average-cost method.

Property, plant, and equipment

Property, plant, and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.

As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply a declining balance method. (See Note 11 – Property, Plant, and Equipment.)

Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Other gains or losses are recorded in Other (income) expense – net included in Operating income (loss) in the Consolidated Statement of Income.

Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment.

We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Income, except for regulated entities, for which the liability is offset by a regulatory asset as management expects to recover amounts in future rates. The regulatory asset is amortized commensurate with our collection of those costs in rates.

Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium.

Goodwill

Goodwill in the Consolidated Balance Sheet represents the excess cost over fair value of the net assets of businesses acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting

88

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess.

Other intangible assets

Our identifiable intangible assets are primarily related to gas gathering, processing and fractionation contracts, and relationships with customers. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.

Impairment of property, plant, and equipment, other identifiable intangible assets, and investments

We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.

We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.

Contingent liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.

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Cash flows from revolving credit facilities and commercial paper program

Proceeds and payments related to borrowings under our credit facilities are reflected in the financing activities in the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 13 – Debt, Banking Arrangements, and Leases.)

Treasury stock

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as Treasury stock in the Consolidated Balance Sheet. Gains and losses on the subsequent reissuance of shares are credited or charged to Capital in excess of par value in the Consolidated Balance Sheet using the average-cost method.

Derivative instruments and hedging activities

We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of physical energy commodities. We report the fair value of derivatives, except for those for which the normal purchases and normal sales exception has been elected, in Other current assets and deferred charges; Regulatory assets, deferred charges, and other;Accrued liabilities, or Other noncurrent liabilities in the Consolidated Balance Sheet. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.

The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

Derivative Treatment	Accounting Method
Normal purchases and normal sales exception	Accrual accounting
Designated in a qualifying hedging relationship	Hedge accounting
All other derivatives	Mark-to-market accounting

We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.

We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costsin the Consolidated Statement of Income.

For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in Product sales or Product costs in the Consolidated Statement of Income. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly

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effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated Statement of Income at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management.

For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product salesorProduct costsin the Consolidated Statement of Income.

Certain gains and losses on derivative instruments included in the Consolidated Statement of Income are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception.

Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.

Revenues

As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.

Service revenues

Revenues from our gas pipeline businesses include services pursuant to long-term firm transportation and storage agreements. These agreements provide for a reservation charge based on the volume of contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for reservation charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges, from both firm and interruptible transportation services, and storage injection and withdrawal services, are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility.

Certain revenues from our midstream operations include those derived from natural gas gathering and processing services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed.

Crude oil gathering and transportation revenues and offshore production handling fees are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed.

Storage revenues from our midstream operations associated with prepaid contracted storage capacity contracts are recognized on a straight-line basis over the life of the contract as services are provided.

Product sales

In the course of providing transportation services to customers of our interstate natural gas pipeline businesses, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided

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for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances.

We market NGLs, crude oil, natural gas, and olefins that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing NGLs are recognized when the products have been sold and delivered.

Under our keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.

Our domestic olefins business produces olefins from purchased or produced feedstock and we recognize revenues when the olefins are sold and delivered.

Our Canadian business has processing and fractionation operations where we retain certain NGLs and olefins from an upgrader’s offgas stream and we recognize revenues when the fractionated products are sold and delivered.

Interest capitalized

We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and where regulation by the FERC exists, on internally generated funds. The latter is included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Income. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.

Employee stock-based awards

We recognize compensation expense on employee stock-based awards, net of estimated forfeitures, on a straight-line basis. (See Note 15 – Stock-Based Compensation.)

Pension and other postretirement benefits

The funded status of each of the pension and other postretirement benefit plans is recognized separately in the Consolidated Balance Sheet as either an asset or liability. The funded status is the difference between the fair value of plan assets and the plan’s benefit obligation. The plans’ benefit obligations and net periodic benefit costs are actuarially determined and impacted by various assumptions and estimates. (See Note 9 – Employee Benefit Plans.)

The discount rates are determined separately for each of our pension and other postretirement benefit plans based on an approach specific to our plans. The year-end discount rates are determined considering a yield curve comprised of high-quality corporate bonds and the timing of the expected benefit cash flows of each plan.

The expected long-term rates of return on plan assets are determined by combining a review of the historical returns within the portfolio, the investment strategy included in the plans’ investment policy statement, and capital market projections for the asset classes in which the portfolio is invested, as well as the weighting of each asset class.

Unrecognized actuarial gains and losses and unrecognized prior service costs and credits are deferred and recorded in accumulated other comprehensive income or, for Transco and Northwest Pipeline, as a regulatory asset or liability, until amortized as a component of net periodic benefit cost. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants’ average remaining future years of service, which is approximately 12 years for our pension plans and approximately 8 years for our other postretirement benefit plans. Unrecognized prior service costs and credits for the other postretirement benefit plans are amortized on a straight line basis over the average remaining years of service to eligibility for eligible plan participants, which is approximately 5 years.

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The expected return on plan assets component of net periodic benefit cost is calculated using the market-related value of plan assets. For our pension plans, the market-related value of plan assets is equal to the fair value of plan assets adjusted to reflect the amortization of gains or losses associated with the difference between the expected and actual return on plan assets over a 5-year period. Additionally, the market-related value of assets may be no more than 110 percent or less than 90 percent of the fair value of plan assets at the beginning of the year. The market-related value of plan assets for our other postretirement benefit plans is equal to the unadjusted fair value of plan assets at the beginning of the year.

Income taxes

We include the operations of our domestic corporate subsidiaries and income from our domestic subsidiary partnerships in our consolidated federal income tax return and also file tax returns in various foreign and state jurisdictions as required. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities. Our management’s judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.

Earnings (loss) per common share

Basic earnings (loss) per common share in the Consolidated Statement of Income is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share in the Consolidated Statement of Income includes any dilutive effect of stock options, nonvested restricted stock units, and convertible debt, unless otherwise noted. Beginning in 2012, we have unvested service-based restricted stock units that contain a nonforfeitable right to dividends during the vesting period and are considered participating securities. Basic and diluted earnings (loss) per common share are calculated using the two-class method and the treasury-stock method. Whichever method results in the most dilutive earnings (loss) per common share is reported.

Foreign currency translation

Certain of our foreign subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of such foreign subsidiaries are translated at the spot rate in effect at the applicable reporting date, and the combined statements of income are translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment is recorded as a separate component of AOCI.

Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates when the transactions are settled result in transaction gains and losses which are reflected in the Consolidated Statement of Income.

Note 2 – Acquisitions, Goodwill, and Other Intangible Assets

Business Combinations

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

On April 27, 2012, WPZ completed the acquisition of 100 percent of the ownership interests in Caiman Eastern Midstream, LLC, from Caiman Energy, LLC in exchange for $1.72 billion in cash and 11,779,296 WPZ common units valued at $603 million (Caiman Acquisition). The fair value of the common units issued as part of the consideration paid was determined on the basis of the closing market price of WPZ’s common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entity operates a gathering and processing business in

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northern West Virginia, southwestern Pennsylvania, and eastern Ohio. Acquisition transaction costs of $16 million were incurred during 2012 related to the Caiman Acquisition and are reported in Selling, general, and administrative expenses at Williams Partners in the Consolidated Statement of Income.

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

	Laser			Caiman
	(Millions)
Assets held-for-sale	$	18		$	—
Other current assets	3			16
Property, plant, and equipment	158			656
Intangible assets:
Customer contracts	316			1,141
Customer relationships	—			250
Other	2			2
Current liabilities	(21		)	(94		)
Noncurrent liabilities	—			(3		)
Identifiable net assets acquired	476			1,968
Goodwill	290			356
	$	766		$	2,324

Revenues and earnings related to the Laser and Caiman Acquisitions included within the Consolidated Statement of Income in 2012 are not material. Supplemental pro forma revenue and earnings for the pre-acquisition periods reflecting these acquisitions as if they had occurred as of January 1, 2011, are not materially different from the information presented in our accompanying Consolidated Statement of Income (since the historical operations of these acquisitions were insignificant relative to our historical operations) and are, therefore, not presented.

Goodwill and Other Intangible Assets

Goodwill

The Laser and Caiman Acquisitions were accounted for as business combinations which, among other things, require assets acquired and liabilities assumed to be measured at their acquisition-date fair values. The excess of cost over those fair values was recorded as goodwill and allocated to WPZ’s Northeast gathering and processing business (the reporting unit) within the Williams Partners segment. Goodwill recognized in the acquisitions relates primarily to enhancing our strategic platform for expansion in the Marcellus and Utica shale plays in the Appalachian basin area. Substantially all of the goodwill is expected to be deductible for tax purposes. Our annual goodwill impairment review did not result in a goodwill impairment in 2013.

Other Intangible Assets

Other intangible assets primarily relate to gas gathering, processing and fractionation contracts and relationships with customers recognized in the Laser and Caiman Acquisitions. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired customer contracts and relationships, which were offset with appropriate charges for the use of contributory assets and discounted using a risk-adjusted discount rate. The intangible assets are being amortized on a straight-line basis over an initial period of 30 years which represents a portion of the term over which the customer contracts and relationships are expected to contribute to our cash flows.

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The gross carrying amount and accumulated amortization of Other intangible assets at December 31 are as follows:

	2013					2012
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
	(Millions)
Customer contracts	$	1,493	$	(88	)	$	1,493	$	(38	)
Customer relationships	250		(14		)	250		(6		)
Other	6		(3		)	6		(1		)
Total	$	1,749	$	(105	)	$	1,749	$	(45	)

We expense costs incurred to renew or extend the terms of our gas gathering, processing and fractionation contracts with customers. Based on the estimated future revenues during the contract periods (as estimated at the time of the respective acquisition), the weighted-average periods prior to the next renewal or extension of the customer contracts associated with the Laser and Caiman Acquisitions were approximately 9 years and 18 years, respectively. Although a significant portion of the expected future cash flows associated with these contracts are dependent on our ability to renew or extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investments required.

The aggregate amortization expense related to Other intangible assets was $60 million, $43 million, and $2 million in 2013, 2012 and 2011, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $60 million.

Purchase of Investment

On December 20, 2012, we purchased an indirect interest in Access GP and limited partner interests in ACMP (collectively referred to as Access Midstream Partners) for approximately $2.19 billion in cash, including transaction costs. We own a 50 percent interest in Access Midstream Ventures, L.L.C., which owns Access GP and its 2 percent general partner interest in ACMP and incentive distribution rights. Also as part of this transaction, we purchased approximately 24 percent of ACMP’s outstanding limited partnership units. ACMP is a publicly traded master limited partnership listed on the New York Stock Exchange that owns, operates, develops, and acquires natural gas gathering systems and other midstream energy assets, which bolsters our position in the Marcellus and Utica shale plays and adds diversity via the Eagle Ford, Haynesville, Barnett, Mid-Continent, and Niobrara areas.

We account for these acquired interests as equity-method investments. The initial difference between the cost of our investment and our proportional share of the underlying equity in the net assets of Access Midstream Partners of $1.27 billion is primarily related to property, plant, and equipment, as well as customer-based intangible assets and goodwill. The portions of the difference related to the property, plant, and equipment and customer-based intangible assets are being depreciated or amortized as appropriate on a straight-line basis as an adjustment to our equity earnings from the investment in Access Midstream Partners over an initial weighted-average period of approximately 18 years.

Our investment in Access Midstream Partners is disclosed as a separate reportable segment. See Note 18 – Segment Disclosures.

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Note 3 – Variable Interest Entities

Consolidated VIEs

As of December 31, 2013, we consolidate the following VIEs:

Gulfstar One

During the second quarter of 2013, a third party contributed $187 million to Gulfstar One LLC (Gulfstar One) in exchange for a 49 percent ownership interest in Gulfstar One. This contribution was based on 49 percent of WPZ’s estimated cumulative net investment at that time. The $187 million was then distributed to WPZ. Following this transaction, WPZ owns a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Gulfstar One’s economic performance. WPZ, as construction agent for Gulfstar One, 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 the third quarter of 2014. WPZ has received certain advance payments from the producer customers and is committed to the producer customers to construct this system. The current estimate of the total remaining construction costs is less than $325 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 One. In December 2013, WPZ committed an additional $134 million to Gulfstar One to fund an expansion of the system that will provide production handling, gathering, and processing services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico. The expansion project is expected to be in service in 2016. The other equity partner has an option to participate in the funding of the expansion project on a proportional basis.

Constitution

WPZ owns a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its firm transportation contracts, is a VIE. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Constitution’s economic performance. WPZ, as construction agent for Constitution, is building a pipeline connecting our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. WPZ plans to place the project in service in late 2015 to 2016and estimates the total remaining construction costs of the project to be less than $600 million, which will be funded with capital contributions from WPZ and the other equity partners, proportional to ownership interest.

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. As of December 31, 2013, 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 as 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 now planned to be in service in mid-to-late 2016. This development stage entity was operating under a preliminary activities budget that governed 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. In February 2014, we agreed with our partner to, among other things, extend the preliminary activities period to March 31, 2014, and change certain rights between the partners that could impact the continued development of the project. We will evaluate the impact of those changes on our determination of the primary beneficiary in the first quarter of

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2014. The remaining amount for spending under the preliminary activities budget through March 31, 2014, is less than $85 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.

As of December 31, 2013, our Consolidated Balance Sheet includes approximately $113 million of capitalized project development costs associated with the Bluegrass Pipeline, included within Construction in progress in the table below. Completion of this project is subject to execution of customer contracts sufficient to support the project. We are in discussions with potential customers regarding commitments to the pipeline and these discussions have not yet yielded sufficient commitments to satisfy this condition. As a result, we evaluated the capitalized project costs for impairment as of December 31, 2013, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including reasonably possible scenarios assuming the construction and operation of the pipeline under differing levels of commitments from customers and the possibility that the project does not proceed. It is reasonably possible that the probability-weighted estimate of undiscounted future net cash flows may change in the near term, resulting in the write-down of this asset to fair value, which could result in all of the capitalized project development costs being expensed. Such changes in estimates could result from lack of sufficient commitments from potential customers, lack of approval of the project by our partner, lack of executed regulatory approvals and unexpected changes in forecasted costs, and other factors impacting project economics.

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:

	December 31,
	2013			2012			Classification
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	122		$	8		Cash and cash equivalents
Construction in progress	1,111			556			Property, plant and equipment, at cost
Accounts payable	(145		)	(128		)	Accounts payable
Construction retainage	(3		)	—			Accrued liabilities
Current deferred revenue	(10		)	—			Accrued liabilities
Noncurrent deferred revenue associated with customer advance payments	(115		)	(109		)	Other noncurrent liabilities

Nonconsolidated VIEs

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

Laurel Mountain

WPZ’s 51 percent-owned equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain) is considered to be a VIE generally due to contractual provisions that transfer certain risks to customers. As decisions about the activities that most significantly impact the economic performance of this entity require a unanimous vote of all members, WPZ is not the primary beneficiary. Our maximum exposure to loss is limited to the carrying value of this investment, which was $481 millionat December 31, 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

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economic performance. At December 31, 2013, the carrying value of our investment in Caiman II was $256 million, which substantially reflects our contributions to that date. In January 2014, WPZ increased its total commitment for contributions to fund the project from $380 million to $500 million inclusive of contributions made to date, which represents WPZ’s current maximum exposure to loss related to this investment.

Moss Lake

Our equity-method investments in Moss Lake Fractionation LLC and Moss Lake LPG Terminal LLC (collectively referred to as Moss Lake) are VIEs because they have insufficient equity to finance activities during their development stage. We currently own 50 percent of these joint projects which plan 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. Additionally, Moss Lake plans to construct a new liquefied petroleum gas (LPG) terminal. 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 investments in Moss Lake at December 31, 2013, was $12 million, which represents our contributions to date. These development stage entities were operating under a preliminary activities budget that governed the spending levels through February 28, 2014. Prior to that time, certain elections by either partner could change the relative ownership of the entities, impact the continued development of the project, and/or revise the determination of the primary beneficiary. In February 2014, we agreed with our partner to, among other things, extend the preliminary activities period to March 31, 2014, and change certain rights between the partners that could impact the continued development of these projects. We will evaluate the impact of those changes on our determination of the primary beneficiary in the first quarter of 2014. The amount we may spend in order to fund our proportional share of the preliminary activities budget through March 31, 2014, is less than $25 million. Continued investment in this project beyond the preliminary activities stage will require additional significant capital contributions.

Note 4 – Discontinued Operations

On December 31, 2011, we completed the tax-free spin-off of our 100 percent interest in WPX to our stockholders. (See Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

The following table reflects summarized results of discontinued operations. The summarized results of discontinued operations for 2013 reflect an unfavorable ruling associated with our former Alaska refinery related to the Trans-Alaska Pipeline System Quality Bank. The summarized results of discontinued operations for 2012 primarily include a gain on reconsolidation following the sale of certain of our former Venezuela operations, whose facilities were expropriated by the Venezuelan government in May 2009. The summarized results of discontinued operations for 2011 reflect the results of operations of our former exploration and production business as discontinued operations.

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Summarized Results of Discontinued Operations

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Revenues	$	—		$	—		$	3,997
Income (loss) from discontinued operations before gain on reconsolidation, impairments, and income taxes	$	(15	)	$	(16	)	$	223
Gain on reconsolidation	—			144			—
Impairments	—			—			(755		)
(Provision) benefit for income taxes	4			8			115
Income (loss) from discontinued operations	$	(11	)	$	136		$	(417	)
Income (loss) from discontinued operations:
Attributable to noncontrolling interests	$	—		$	—		$	10
Attributable to The Williams Companies, Inc.	$	(11	)	$	136		$	(427	)

Revenues and Income (loss) from discontinued operations before gain on reconsolidation, impairments, and income taxes for 2011 primarily reflect the results of operations of our discontinued exploration and production business. Results for 2011 additionally include $42 million of transaction costs related to the spin-off.

Gain on reconsolidation for 2012 is related to our majority ownership in entities (the Wilpro entities) that owned and operated the El Furrial and PIGAP II gas compression facilities prior to their expropriation by the Venezuelan government in May 2009. We deconsolidated the Wilpro entities in 2009. In 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 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)

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

Impairments in 2011 reflect $367 million and $180 million of impairments of capitalized costs of certain natural gas producing properties of our discontinued exploration and production business in the Powder River basin and the Barnett Shale, respectively, $29 million of write-downs to estimates of fair value less costs to sell the assets of our discontinued exploration and production business in the Arkoma basin, and an impairment of $179 million in connection with the spin-off of WPX to reflect the difference between the carrying value of our investment in WPX and the estimated fair value of WPX at the time of spin-off. (See further discussion below regarding the determination of the fair value of WPX.) These nonrecurring fair value measurements fell within Level 3 of the fair value hierarchy.

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

For our assessment of the carrying value of our natural gas producing properties, we utilized estimates of future cash flows, in certain cases including purchase offers received. Significant judgments and assumptions in these assessments include estimates of natural gas reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and an applicable discount rate commensurate with risk of the underlying cash flow estimates.

(Provision) benefit for income taxes for 2011 includes a $26 million net tax benefit associated with the write-down of certain indebtedness related to our former power operations.

Impairment of our investment in WPX

In conjunction with accounting for the spin-off of WPX, we evaluated whether there was an indicator of impairment of the carrying value of the investment at the date of the spin-off. Because the market capitalization of WPX as determined by its closing stock price on December 30, 2011, pursuant to the “when issued” trading market was less than our investment in WPX, we determined that an indicator of impairment was present and conducted an evaluation of the fair value of our investment in WPX at the date of the spin-off.

To determine the fair value at the time of spin-off, we considered several valuation approaches to derive a range of fair value estimates. These included consideration of the “when issued” stock price at December 30, 2011, an income approach, and a market approach. While the “when issued” stock price approach utilized the most observable inputs of the three approaches, we noted that the short trading duration, low trading volumes, and lack of liquidity in the “when issued” market, among other factors, served to limit this input in being solely determinative of the fair value of WPX. As such, we also considered the other valuation approaches in estimating the overall fair value of WPX, though giving preferential weighting to the “when issued” stock price approach.

Key variables and assumptions included the application of a control premium of up to 30 percent to the December 30, 2011 “when issued” trading value based on transactions involving energy companies. For the income approach, we estimated the fair value of WPX using a discounted cash flow analysis of its oil and natural gas reserves, primarily adjusted for long-term debt. Implicit in this approach was the use of forward market prices and discount rates that considered the risk of the respective reserves. After-tax discount rates assumed to be used by market participants were an average of 11.25 percent for proved reserves, 13.25 percent to 15.25 percent for probable reserves, and 15.25 percent to 18.25 percent for possible reserves. For the market approach, we considered multiples of cash flows derived from the value of comparable companies utilizing their respective traded stock prices, adjusted for a control premium consistent with levels noted above. Using these methodologies, we computed a range of estimated fair values from $4.5 billion to $6.7 billion. After giving preferential weighting to the “when issued” valuation, we computed an estimated fair value of approximately $5.5 billion.

As a result of this evaluation, we recorded an impairment charge which is nondeductible for tax purposes. This amount served to reduce the investment basis of the net assets accounted for as a dividend upon the spin-off at December 31, 2011.

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Energy Commodity Derivatives Gains and Losses

The following table presents pre-tax gains and losses for our former exploration and production business’ energy commodity derivatives.

	Year Ended December 31, 2011		Classification
	(Millions)
Designated as cash flow hedges:
Net gain (loss) recognized in other comprehensive income (loss) (effective portion)	$	413	AOCI
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$	332	Income (loss) from discontinued operations
Not designated as cash flow hedges:
Gain (loss) recognized in income	$	30	Income (loss) from discontinued operations

Note 5 – Investing Activities

Investing Income

	Years Ended December 31,
	2013		2012		2011
	(Millions)
Equity earnings (losses) (1)	$	134	$	111	$	155
Income (loss) from investments (1)	28		49		7
Interest income and other	53		28		6
Total investing income	$	215	$	188	$	168

__________

(1) Items also included in Segment profit (loss). (See Note 18 – Segment Disclosures.)

Equity earnings (losses)

In December 2012, we acquired certain interests in Access Midstream Partners for approximately $2.19 billion in cash. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.) Equity earnings (losses) in 2013 includes $93 million of equity earnings recognized from Access Midstream Partners, offset by $63 million noncash amortization of the difference between the cost of our investment and our underlying share of the net assets of Access Midstream Partners.

Income (loss) from investments

Included in Income (loss) from investments for 2013 is a $31 million gain resulting from Access Midstream Partners’ equity issuances during 2013. These equity issuances resulted in the dilution of our limited partner interest from approximately 24 percent to 23 percent, which is accounted for as though we sold a portion of our investment.

In 2010, we sold our 50 percent interest in Accroven SRL (Accroven) to the state-owned oil company, Petróleos de Venezuela S.A. (PDVSA). Income (loss) from investments in 2012 and 2011 includes gains of $53 million and $11 million, respectively, from the sale. Payments were recognized upon receipt, as future collections were not reasonably assured.

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Interest income and other

Interest income and other includes $50 million and $7 million of interest income for 2013 and 2012, respectively, associated with a receivable related to the sale of certain former Venezuela assets. (See Note 4 – Discontinued Operations). The 2013 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.

Additionally, Interest income and other for 2012 includes $10 million of interest related to the 2010 sale of Accroven discussed above.

Investments

	December 31,
	2013		2012
	(Millions)
Equity method:
Access Midstream Partners — 24%	$	2,161	$	2,187
Overland Pass Pipeline Company LLC (OPPL) — 50%	452		454
Gulfstream — 50%	333		348
Discovery Producer Services LLC (Discovery) — 60% (1)	527		350
Laurel Mountain — 51% (1)	481		444
Caiman II — 47.5%	256		67
Other	150		137
	$	4,360	$	3,987

_________

(1) We account for these investments under the equity method due to the significant participatory rights of our partners such that we do not control or are otherwise not the primary beneficiary of the investments.

Related party transactions

We have purchases from our equity-method investees included in Product costs in the Consolidated Statement of Income of $161 million, $186 million, and $234 million for the years ended 2013, 2012, and 2011, respectively. We have $13 million and $15 million included in Accounts payable in the Consolidated Balance Sheet with our equity-method investees at December 31, 2013 and 2012, respectively.

WPZ has operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to WPZ for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. We supplied a portion of these services, primarily those related to employees since WPZ does not have any employees, to certain equity-method investees. The total gross charges to equity-method investees for these fees included in the Consolidated Statement of Income are $67 million, $75 million and $57 million for the years ended 2013, 2012, and 2011, respectively.

Equity-method investments

We have differences between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees of $1.13 billion at December 31, 2013. This difference primarily relates to our investment in Access Midstream Partners resulting from property, plant, and equipment, as well as customer-based intangible assets and goodwill. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)

We generally fund our portion of significant expansion or development projects of these investees, except for Access Midstream Partners which is expected to be self-funding, through additional capital contributions. As of December 31, 2013, our proportionate share of amounts remaining to be spent for specific capital projects already in

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

progress for Discovery, Laurel Mountain, and Caiman II totaled $244 million, $72 million, and $119 million, respectively.

We contributed $193 million and $169 million to Discovery in 2013 and 2012, respectively; $42 million, $174 million, and $137 million to Laurel Mountain in 2013, 2012 and 2011, respectively; and $192 million and $69 million, to Caiman II in 2013 and 2012, respectively.

Our equity-method investees’ organizational documents generally require distribution of available cash to equity holders on a quarterly basis. Dividends and distributions, including those presented below, received from companies accounted for by the equity method were $247 million, $173 million, and $193 million in 2013, 2012, and 2011, respectively. These transactions reduced the carrying value of our investments. These dividends and distributions primarily included:

	2013		2012		2011
	(Millions)
Access Midstream Partners	$	93	$	—	$	—
Gulfstream	81		79		84
Discovery	12		21		40
Aux Sable Liquid Products L.P.	20		28		35
OPPL	27		28		19

Summarized Financial Position and Results of Operations of All Equity-Method Investments

	December 31,
	2013			2012
	(Millions)
Assets (liabilities):
Current assets	$	689		$	582
Noncurrent assets	13,621			11,571
Current liabilities	(573		)	(507		)
Noncurrent liabilities	(4,563		)	(3,807		)
Noncontrolling interest	(254		)	(112		)

	Years Ended December 31,
	2013		2012		2011
	(Millions)
Gross revenue	$	2,406	$	1,821	$	1,808
Operating income	699		557		747
Net income	627		488		654

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 6 – Other Income and Expenses

The following table presents significant gains or losses reflected in Other (income) expense – net within Costs and expenses:

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Williams Partners
Net insurance recoveries associated with the Geismar Incident	$	(40	)	$	—		$	—
Amortization of regulatory assets associated with asset retirement obligations	30			7			6
Write-off of the Eminence abandonment regulatory asset not recoverable through rates	12			—			—
Insurance recoveries associated with the Eminence abandonment	(16		)	—			—
Settlement in principle of a producer claim	25			—			—
Project feasibility costs	4			21			10
Capitalization of project feasibility costs previously expensed	(1		)	(19		)	(11		)
Williams NGL & Petchem Services
Gulf Liquids litigation contingency accrual reduction (see Note 17)	—			—			(19		)
Write-off of an abandoned project	20			—			—

The reversals of project feasibility costs from expense to capital at Williams Partners are associated with natural gas pipeline expansion projects. These reversals were made upon determining that the related projects were probable of development. These costs are now included in the capital costs of the projects, which we believe are probable of recovery through the project rates.

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

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

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

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

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

We have expensed $13 million at Williams Partners during 2013 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 December 31, 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. During the fourth quarter of 2013, we incurred $10 million of covered insurable expenses in excess of our retentions (deductibles) which partially

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

offset the $50 million gain included in Other (income) expense – net within Costs and expenses in our Consolidated Statement of Income.

Additional Items

We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December 28, 2010. We recorded $3 million, $2 million, and $15 million of charges to Operating and maintenance expenses at Williams Partners during 2013, 2012, and 2011, respectively, primarily related to assessment and monitoring costs incurred to ensure the safety of the surrounding area.

We engaged a consulting firm in 2012 to assist in better aligning resources to support our business strategy following the spin-off of WPX. In 2012, we recorded $26 million of reorganization-related costs, including consulting costs, to Selling, general, and administrative expenses.

In conjunction with the Gulf Liquids litigation contingency accrual reduction noted in the table above, Williams NGL & Petchem Services also reduced an accrual for the associated interest of $14 million in 2011, which is reflected in Interest incurred. (See Note 17 – Contingent Liabilities and Commitments.)

In conjunction with the completion of a tender offer for a portion of our debt in the fourth quarter of 2011, we incurred $271 million of Early debt retirement costs, consisting primarily of cash premiums.

Note 7 – Provision (Benefit) for Income Taxes

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

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Current:
Federal	$	(17	)	$	91		$	181
State	7			17			13
Foreign	(13		)	40			(6		)
	(23		)	148			188
Deferred:
Federal	348			220			(61		)
State	40			(13		)	(14		)
Foreign	36			5			11
	424			212			(64		)
Total provision (benefit)	$	401		$	360		$	124

105

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Reconciliations from the Provision (benefit) for income taxes from continuing operations at the federal statutory rate to the recorded Provision (benefit) for income taxes are as follows:

	Years Ended December 31,
	2013			2012			2011
	(Millions)
Provision (benefit) at statutory rate	$	378		$	451		$	421
Increases (decreases) in taxes resulting from:
Impact of nontaxable noncontrolling interests	(78		)	(72		)	(96		)
State income taxes (net of federal benefit)	26			2			11
Foreign operations — net	(32		)	(36		)	(14		)
Federal settlements	—			—			(109		)
International revised assessments	—			—			(38		)
Taxes on undistributed earnings of foreign subsidiaries - net	99			—			(66		)
Other — net	8			15			15
Provision (benefit) for income taxes	$	401		$	360		$	124

The 2013 state deferred provision includes $10 million, net of federal benefit, related to the impact of a second-quarter Texas franchise tax law change.

Income (loss) from continuing operations before income taxes includes $119 million, $196 million, and $173 million of foreign income in 2013, 2012, and 2011, respectively.

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 recognized $99 million of deferred income tax expense in continuing operations and $24 million of deferred tax benefit in AOCI during the fourth quarter of 2013. As a result of this transaction, we estimate approximately $111 million will be characterized as a current income tax liability in the first quarter of 2014.

During the third quarter of 2011, associated with a ruling received from the Internal Revenue Service (IRS) related to our plan to separate our exploration and production business through an initial public offering and subsequent tax-free spin-off, and following a certain internal reorganization, we recognized a deferred tax benefit of $66 million as we considered the undistributed earnings of certain foreign operations to be permanently reinvested.

During the course of audits of our business by domestic and foreign tax authorities, we frequently face challenges regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various filing positions, we apply the two step process of recognition and measurement. In association with this liability, we record an estimate of related interest and tax exposure as a component of our tax provision. The impact of this accrual is included within other — net in our reconciliation of the tax provision to the federal statutory rate.

106

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Significant components of deferred tax liabilities and deferred tax assets are as follows:

	December 31,
	2013		2012
	(Millions)
Deferred tax liabilities:
Property, plant, and equipment	$	102	$	72
Undistributed earnings of foreign subsidiaries	75		—
Investments	3,663		3,146
Other	—		34
Total deferred tax liabilities	3,840		3,252
Deferred tax assets:
Accrued liabilities	126		313
Federal tax credits	108		74
State losses and credits	194		195
Other	91		90
Total deferred tax assets	519		672
Less valuation allowance	181		144
Net deferred tax assets	338		528
Overall net deferred tax liabilities	$	3,502	$	2,724

The valuation allowance at December 31, 2013 and 2012 serves to reduce the available deferred tax assets to an amount that will, more likely than not, be realized. The amounts presented in the table above are, with respect to state items, before any federal benefit. The change from prior year for the state losses and credits is primarily due to increases in losses and credits generated in the current and prior years less losses and credits utilized in the current year. We have loss and credit carryovers in multiple state taxing jurisdictions. These attributes generally expire between 2014 and 2033 with some carryovers having indefinite carryforward periods. In the case of the valuation allowance, the change is due to the ongoing evaluation process of the losses and credits anticipated to be realized in future years. The federal tax credits currently have no expiration dates.

 During 2013, we received cash refunds (net of payments) for income taxes of $50 million. Cash payments for income taxes (net of refunds and including discontinued operations) were $198 million and $296 million in 2012 and 2011, respectively.

As of December 31, 2013, we had approximately $66 million of unrecognized tax benefits. If recognized, income tax expense would be reduced by $70 million, including the effect of these changes on other tax attributes, with state income tax amounts included net of federal tax effect. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	2013			2012
	(Millions)
Balance at beginning of period	$	58		$	38
Additions based on tax positions related to the current year	4			4
Additions for tax positions of prior years	18			22
Reductions for tax positions of prior years	(2		)	(6		)
Settlement with taxing authorities	(12		)	—
Balance at end of period	$	66		$	58

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

We recognize related interest and penalties as a component of income tax provision. Total interest and penalties recognized as part of income tax provision were expense of $9 million for 2013, and benefits of $7 million and $56 million for 2012 and 2011, respectively. Approximately $16 million and $7 million of interest and penalties primarily relating to uncertain tax positions have been accrued as of December 31, 2013 and 2012, respectively.

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.

During the first quarter of 2011, we finalized settlements for 1997 through 2008 on certain contested matters with the IRS that resulted in a 2011 tax benefit of approximately $109 million. In July and August 2011, we made cash payments to the IRS of $82 million and $77 million, respectively, related to these settlements. During the first and fourth quarters of 2011, we received revised assessments on an international matter that resulted in a 2011 tax benefit of approximately $38 million. In the first quarter of 2012, we received a cash refund for the revised assessments of $21 million.

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

Tax years after 2010 are subject to examination by the IRS. The statute of limitations for most states expires one year after expiration of the IRS statute. Generally, tax returns for our Venezuelan and Canadian entities are open to audit for tax years after 2007, although Venezuela is subject to certain contractual limitations. A reassessment of a Canadian audit for the years 2007 through 2010 is still outstanding as of December 31, 2013. The impact of this reassessment is not expected to be material.

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.

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 by a reduction in the tax resulting from the 2009 to 2010 IRS settlement.

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 8 – Earnings (Loss) Per Common Share from Continuing Operations

	Years Ended December 31,
	2013		2012		2011
	(Dollars in millions, except per-share amounts; shares in thousands)
Income (loss) from continuing operations attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share	$	441	$	723	$	803
Basic weighted-average shares	682,948		619,792		588,553
Effect of dilutive securities:
Nonvested restricted stock units	1,995		2,694		4,332
Stock options	2,149		2,608		3,374
Convertible debentures	93		392		1,916
Diluted weighted-average shares	687,185		625,486		598,175
Earnings (loss) per common share from continuing operations:
Basic	$	.65	$	1.17	$	1.36
Diluted	$	.64	$	1.15	$	1.34

Beginning in 2012, we have nonvested service-based restricted stock units that contain a nonforfeitable right to dividends during the vesting period and are considered participating securities. Dividends associated with these participating securities were $2 million and $1 million for 2013 and 2012, respectively, and have been subtracted from Income (loss) from continuing operations attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share in the calculation of earnings (loss) per common share.

Note 9 – Employee Benefit Plans

We have noncontributory defined benefit pension plans in which all eligible employees participate. Currently, eligible employees earn benefits primarily based on a cash balance formula. Various other formulas, as defined in the plan documents, are utilized to calculate the retirement benefits for plan participants not covered by the cash balance formula. At the time of retirement, participants may elect, to the extent they are eligible for the various options, to receive annuity payments, a lump sum payment, or a combination of a lump sum and annuity payments. In addition to our pension plans, we currently provide subsidized retiree medical and life insurance benefits (other postretirement benefits) to certain eligible participants. Generally, employees hired after December 31, 1991, are not eligible for the subsidized retiree medical benefits, except for participants that were employees or retirees of Transco Energy Company on December 31, 1995, and other miscellaneous defined participant groups. For the periods presented, certain of these other postretirement benefit plans, particularly the subsidized retiree medical benefit plans, provide for retiree contributions and contain other cost-sharing features such as deductibles, co-payments, and co-insurance. The accounting for these plans anticipates future cost-sharing that is consistent with our expressed intent to increase the retiree contribution level generally in line with health care cost increases. Effective January 1, 2014, subsidized retiree medical benefits for eligible participants age 65 and older will be paid through contributions to health reimbursement accounts. The impact of this plan change is reflected in the December 31, 2013, other postretirement benefit obligation.

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Funded Status

The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits for the years indicated.

	Pension Benefits						Other Postretirement Benefits
	2013			2012			2013			2012
	(Millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,549		$	1,441		$	331		$	339
Service cost	44			39			2			3
Interest cost	51			55			11			13
Plan participants’ contributions	—			—			6			5
Benefits paid	(87		)	(75		)	(19		)	(20		)
Medicare Part D subsidy	—			—			4			3
Plan amendment	—			—			(59		)	(6		)
Actuarial loss (gain)	(173		)	98			(63		)	(6		)
Settlements	—			(9		)	—			—
Benefit obligation at end of year	1,384			1,549			213			331
Change in plan assets:
Fair value of plan assets at beginning of year	1,071			965			175			159
Actual return on plan assets	165			111			31			18
Employer contributions	92			79			8			13
Plan participants’ contributions	—			—			6			5
Benefits paid	(87		)	(75		)	(19		)	(20		)
Settlements	—			(9		)	—			—
Fair value of plan assets at end of year	1,241			1,071			201			175
Funded status — underfunded	$	(143	)	$	(478	)	$	(12	)	$	(156	)
Accumulated benefit obligation	$	1,359		$	1,519

The underfunded status of our pension plans and other postretirement benefit plans presented in the previous table are recognized in the Consolidated Balance Sheet within the following accounts:

	December 31,
	2013		2012
	(Millions)
Underfunded pension plans:
Current liabilities	$	1	$	3
Noncurrent liabilities	142		475
Underfunded other postretirement benefit plans:
Current liabilities	8		8
Noncurrent liabilities	4		148

The plan assets within our other postretirement benefit plans are intended to be used for the payment of benefits for certain groups of participants. The Current liabilities for the other postretirement benefit plans represent the current portion of benefits expected to be payable in the subsequent year for the groups of participants whose benefits are not expected to be paid from plan assets.

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Notes to Consolidated Financial Statements – (Continued)

The pension plans’ benefit obligation Actuarial loss (gain) of $(173) million in 2013 and $98 million in 2012 are primarily due to the impact of changes in the discount rates utilized to calculate the benefit obligations. In 2013, these rates increased, while in 2012 these rates decreased, as compared to those of the preceding year.

The 2013 benefit obligation Actuarial loss (gain) of $(63) million for our other postretirement benefit plans is primarily due to the impact of an increase in the discount rates utilized to calculate the benefit obligation as well as favorable claims experience. The Plan amendment for the other postretirement benefit plans of $(59) million in 2013 reflects a change in the plans to provide subsidized retiree medical benefits through defined annual contributions to health reimbursement accounts for eligible participants age 65 and older effective January 1, 2014. The 2012 benefit obligation Actuarial loss (gain) of $(6) million for our other postretirement benefit plans is primarily due to changes to claims experience and health care cost trend rates, offset by the impact of a decrease in the discount rates utilized to calculate the benefit obligation.

At December 31, 2013 and 2012, all of our pension plans had a projected benefit obligation and accumulated benefit obligation in excess of plan assets.

Pre-tax amounts not yet recognized in Net periodic benefit cost at December 31 are as follows:

	Pension Benefits						Other Postretirement Benefits
	2013			2012			2013			2012
	(Millions)
Amounts included in Accumulated other comprehensive income (loss):
Prior service (cost) credit	$	—		$	(1	)	$	26		$	7
Net actuarial loss	(491		)	(828		)	(11		)	(35		)
Amounts included in regulatory assets/liabilities associated with Transco and Northwest Pipeline:
Prior service credit	N/A			N/A			$	42		$	14
Net actuarial loss	N/A			N/A			(2		)	(67		)

In addition to the regulatory assets/liabilities included in the previous table, differences in the amount of actuarially determined Net periodic benefit cost for our other postretirement benefit plans and the other postretirement benefit costs recovered in rates for Transco and Northwest Pipeline are deferred as a regulatory asset or liability. We have regulatory liabilities of $44 million at December 31, 2013 and $38 million at December 31, 2012 related to these deferrals. These amounts will be reflected in future rates based on the rate structures of these gas pipelines.

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Net Periodic Benefit Cost

Net periodic benefit cost for the years ended December 31 consist of the following:

	Pension Benefits									Other Postretirement  Benefits
	2013			2012			2011			2013			2012			2011
	(Millions)
Components of net periodic benefit cost:
Service cost	$	44		$	39		$	41		$	2		$	3		$	2
Interest cost	51			55			64			11			13			15
Expected return on plan assets	(61		)	(64		)	(77		)	(9		)	(9		)	(10		)
Amortization of prior service cost (credit)	1			1			1			(12		)	(7		)	(11		)
Amortization of net actuarial loss	60			53			38			4			8			3
Net actuarial loss from settlements	—			5			4			—			—			—
Reclassification to regulatory liability	—			—			—			2			—			1
Net periodic benefit cost	$	95		$	89		$	71		$	(2	)	$	8		$	—

Included in Net periodic benefit cost in 2011 in the previous table is cost associated with active and former employees that supported WPX’s operations (See Note 4 – Discontinued Operations). This cost was directly charged to WPX and is included in Income (loss) from discontinued operations. These amounts totaled $8 million in 2011 for our pension plans and totaled less than $1 million in 2011 for our other postretirement benefit plans.

Items Recognized in Other Comprehensive Income (Loss) and Regulatory Assets/Liabilities

Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) before taxes for the years ended December 31 consist of the following:

	Pension Benefits								Other Postretirement  Benefits
	2013		2012			2011			2013			2012			2011
	(Millions)
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss):
Net actuarial gain (loss)	$	277	$	(51	)	$	(220	)	$	23		$	2		$	(21	)
Prior service credit	—		—			—			23			2			2
Amortization of prior service cost (credit)	1		1			1			(4		)	(3		)	(4		)
Amortization of net actuarial loss and loss from settlements	60		58			42			1			3			1
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss)	$	338	$	8		$	(177	)	$	43		$	4		$	(22	)

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Other changes in plan assets and benefit obligations for our other postretirement benefit plans associated with Transco and Northwest Pipeline are recognized in regulatory assets/liabilities.Amounts recognized in regulatory assets/ liabilities for the years ended December 31 consist of the following:

	2013			2012			2011
	(Millions)
Net actuarial gain (loss)	$	62		$	13		$	(39	)
Prior service credit	36			4			1
Amortization of prior service credit	(8		)	(4		)	(7		)
Amortization of net actuarial loss	3			5			2

Pre-tax amounts expected to be amortized in Net periodic benefit cost in 2014 are as follows:

	Pension Benefits		Other Postretirement Benefits
	(Millions)
Amounts included in Accumulated other comprehensive income (loss):
Prior service cost (credit)	$	—	$	(8	)
Net actuarial loss	38		—
Amounts included in regulatory assets/liabilities associated with Transco and Northwest Pipeline:
Prior service credit	N/A		$	(12	)
Net actuarial loss	N/A		—

Key Assumptions

The weighted-average assumptions utilized to determine benefit obligations as of December 31 are as follows:

	Pension Benefits				Other Postretirement Benefits
	2013		2012		2013		2012
Discount rate	4.68	%	3.43	%	4.80	%	3.77	%
Rate of compensation increase	4.56		4.57		N/A		N/A

The weighted-average assumptions utilized to determine Net periodic benefit cost for the years ended December 31 are as follows:

	Pension Benefits						Other Postretirement  Benefits
	2013		2012		2011		2013		2012		2011
Discount rate	3.43	%	3.98	%	5.19	%	3.97	%	4.22	%	5.35	%
Expected long-term rate of return on plan assets	5.90		6.30		7.50		5.26		5.71		6.54
Rate of compensation increase	4.57		4.52		5.00		N/A		N/A		N/A

The increase in discount rates from December 31, 2012 to December 31, 2013 is primarily due to the general market increase in yields on long-term, high-quality corporate debt securities. The expected long-term rates of return on plan assets assumptions decreased in 2013 as a result of a decrease in the forward-looking capital market projections.

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The mortality assumptions used to determine the obligations for our pension and other postretirement benefit plans are the estimate of expected mortality rates for the participants in these plans. The selected mortality tables are among the most recent tables available and include projected mortality improvements.

The assumed health care cost trend rate for 2014 is 7.2 percent. This rate decreases to 5.0 percent by 2023. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	Point increase		Point decrease
	(Millions)
Effect on total of service and interest cost components	$	1	$	(1	)
Effect on other postretirement benefit obligation	7		(6		)

Plan Assets

The investment policy for our pension and other postretirement benefit plans provides for an investment strategy in accordance with the Employee Retirement Income Security Act (ERISA), which governs the investment of the assets in a diversified portfolio. The plans follow a policy of diversifying the investments across various asset classes and investment managers. Additionally, the investment returns on approximately 40 percent of the other postretirement benefit plan assets are subject to income tax; therefore, certain investments are managed in a tax efficient manner.

The pension plans’ target asset allocation range at December 31, 2013 was 54 percent to 66 percent equity securities, which includes the commingled investment funds invested in equity securities, and 36 percent to 44 percent fixed income securities, including the fixed income commingled investment fund, and cash management funds. Within equity securities, the target range for U.S. equity securities is 37 percent to 45 percent and international equity securities is 17 percent to 21 percent. The asset allocation continues to be weighted toward equity securities since the obligations of the pension and other postretirement benefit plans are long-term in nature and historically equity securities have outperformed other asset classes over long periods of time.

Equity security investments are restricted to high-quality, readily marketable securities that are actively traded on the major U.S. and foreign national exchanges. Investment in Williams’ securities or an entity in which Williams has a majority ownership is prohibited in the pension plans except where these securities may be owned in a commingled investment fund in which the plans’ trusts invest. No more than 5 percent of the total stock portfolio valued at market may be invested in the common stock of any one corporation.

The following securities and transactions are not authorized: unregistered securities, commodities or commodity contracts, short sales or margin transactions, or other leveraging strategies. Investment strategies using the direct holding of options or futures require approval and, historically, have not been used; however, these instruments may be used in commingled investment funds. Additionally, real estate equity and natural resource property investments are generally restricted.

Fixed income securities are generally restricted to high-quality, marketable securities that may include, but are not necessarily limited to, U.S. Treasury securities, U.S. government guaranteed and nonguaranteed mortgage-backed securities, government and municipal bonds, and investment grade corporate securities. Theoverall rating of the fixed income security assets is generally required to be at least “A,” according to the Moody’s or Standard & Poor’s rating systems. No more than 5 percent of the total fixed income portfolio may be invested in the fixed income securities of any one issuer with the exception of bond index funds and U.S. government guaranteed and agency securities.

During 2013, ten active investment managers and one passive investment manager managed substantially all of the pension plans’ funds and four active investment managers and one passive investment manager managed the other postretirement benefit plans’ funds. Each of the managers had responsibility for managing a specific portion of these assets and each investment manager was responsible for 1 percent to 15 percent of the assets.

The pension and other postretirement benefit plans’ assets are held primarily in equity securities, including commingled investment funds invested in equity securities, and fixed income securities, including a commingled fund

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Notes to Consolidated Financial Statements – (Continued)

invested in fixed income securities. Within the plans’ investment securities, there are no significant concentrations of risk because of the diversity of the types of investments, diversity of the various industries, and the diversity of the fund managers and investment strategies. Generally, the investments held in the plans are publicly traded, therefore, minimizing liquidity risk in the portfolio.

The fair values of our pension plan assets at December 31, 2013 and 2012 by asset class are as follows:

	2013
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Pension assets:
Cash management fund	$	23	$	—	$	—	$	23
Equity securities:
U.S. large cap	211		—		—		211
U.S. small cap	146		—		—		146
International developed markets large cap growth	—		59		—		59
Preferred stock	2		—		—		2
Commingled investment funds:
Equities — U.S. large cap (1)	—		179		—		179
Equities — International small cap (2)	—		24		—		24
Equities — Emerging markets value (3)	—		34		—		34
Equities — Emerging markets growth (4)	—		19		—		19
Equities — International developed markets large cap value (5)	—		100		—		100
Fixed income — Corporate bonds (6)	—		140		—		140
Fixed income securities (7):
U.S. Treasury securities	30		—		—		30
Mortgage-backed securities	—		67		—		67
Corporate bonds	—		200		—		200
Insurance company investment contracts and other	—		7		—		7
Total assets at fair value at December 31, 2013	$	412	$	829	$	—	$	1,241

115

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

	2012
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Pension assets:
Cash management fund	$	21	$	—	$	—	$	21
Equity securities:
U.S. large cap	169		—		—		169
U.S. small cap	115		—		—		115
International developed markets large cap growth	1		61		—		62
Emerging markets growth	3		18		—		21
Preferred stock	6		—		—		6
Commingled investment funds:
Equities — U.S. large cap (1)	—		146		—		146
Equities — Emerging markets value (3)	—		33		—		33
Equities — International developed markets large cap value (5)	—		83		—		83
Fixed income — Corporate bonds (6)	—		150		—		150
Fixed income securities (7):
U.S. Treasury securities	22		—		—		22
Mortgage-backed securities	—		68		—		68
Corporate bonds	—		171		—		171
Insurance company investment contracts and other	—		4		—		4
Total assets at fair value at December 31, 2012	$	337	$	734	$	—	$	1,071

116

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The fair values of our other postretirement benefits plan assets at December 31, 2013 and 2012 by asset class are as follows:

	2013
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Other postretirement benefit assets:
Cash management funds	$	13	$	—	$	—	$	13
Equity securities:
U.S. large cap	52		—		—		52
U.S. small cap	29		—		—		29
International developed markets large cap growth	—		15		—		15
Emerging markets growth	1		1		—		2
Commingled investment funds:
Equities — U.S. large cap (1)	—		18		—		18
Equities — International small cap (2)	—		2		—		2
Equities — Emerging markets value (3)	—		4		—		4
Equities — Emerging markets growth (4)	—		2		—		2
Equities — International developed markets large cap value (5)	—		10		—		10
Fixed income — Corporate bonds (6)	—		14		—		14
Fixed income securities (8):
U.S. Treasury securities	3		—		—		3
Government and municipal bonds	—		10		—		10
Mortgage-backed securities	—		7		—		7
Corporate bonds	—		20		—		20
Total assets at fair value at December 31, 2013	$	98	$	103	$	—	$	201

117

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

	2012
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(Millions)
Other postretirement benefit assets:
Cash management funds	$	14	$	—	$	—	$	14
Equity securities:
U.S. large cap	42		—		—		42
U.S. small cap	21		—		—		21
International developed markets large cap growth	—		13		—		13
Emerging markets growth	1		4		—		5
Preferred stock	1		—		—		1
Commingled investment funds:
Equities — U.S. large cap (1)	—		15		—		15
Equities — Emerging markets value (3)	—		3		—		3
Equities — International developed markets large cap value (5)	—		9		—		9
Fixed income — Corporate bonds (6)	—		15		—		15
Fixed income securities (8):
U.S. Treasury securities	2		—		—		2
Government and municipal bonds	—		10		—		10
Mortgage-backed securities	—		7		—		7
Corporate bonds	—		18		—		18
Total assets at fair value at December 31, 2012	$	81	$	94	$	—	$	175

____________

(1) The stated intent of this fund is to invest primarily in equity securities comprising the Standard & Poor’s 500 Index. The investment objective of the fund is to approximate the performance of the Standard & Poor’s 500 Index over the long term. The fund manager retains the right to restrict withdrawals from the fund so as not to disadvantage other investors in the fund.

(2) The stated intent of this fund is to invest in equity securities of international small capitalization companies for the purpose of capital appreciation. The fund invests primarily in equity securities of non-U.S. issuers and other Depository Receipts listed on globally recognized exchanges. The fund may also invest up to 15 percent of its net asset value in emerging markets. The plans’ trustee is required to notify the fund manager 10 days prior to a withdrawal from the fund. For any redemption made within 180 days of contribution, the fund reserves the right to charge a 1.5 percent redemption fee. The fund also reserves the right to make all or a portion of redemptions in-kind rather than in cash or in a combination of cash and in-kind.

(3) The stated intent of this fund is to invest in equity securities of international emerging markets for the purpose of capital appreciation. The fund invests primarily in common stocks in the financial, consumer goods, information technology, energy, telecommunications, materials, and industrial sectors. The plans’ trustee is required to notify the fund manager 10 days prior to a withdrawal from the fund. The fund manager retains the right to restrict withdrawals from the fund so as not to disadvantage other investors in the fund.

(4) The stated intent of this fund is to invest mainly in equity securities of emerging market companies, or those companies that derive a significant portion of their revenues or profits from emerging economies for the purpose of long-term capital growth. The plans’ trustee is required to notify the fund manager 15 days prior to a withdrawal

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

from the fund as of the last day of any month. The fund reserves the right to suspend and compel withdrawals. The fund also reserves the right to make all or a portion of redemptions in-kind rather than in cash or in a combination of cash and in-kind.

(5) The stated intent of this fund is to invest in a diversified portfolio of international equity securities for the purpose of capital appreciation. The fund invests primarily in common stocks in the consumer goods, financial, health care, industrial, materials, energy, and information technology sectors. The plans’ trustee is required to notify the fund manager 10 days prior to a withdrawal from the fund. The fund manager retains the right to restrict withdrawals from the fund so as not to disadvantage other investors in the fund.

(6) The stated intent of this fund is to invest in U.S. Corporate bonds and U.S. Treasury securities. The fund is managed to closely match the characteristics of a long-term corporate bond index fund and seeks to maintain an average credit quality target of A- or above and a maximum 10 percent allocation to BBB rated securities. The fund’s target duration is approximately 20 years. The trustee of the fund reserves the right to delay the processing of deposits or withdrawals in order to ensure that securities transactions will be carried out in an orderly manner.

(7) The weighted-average credit quality rating of the pension assets fixed income security portfolio is investment grade with a weighted-average duration of approximately 6 years for 2013 and 2012.

(8) The weighted-average credit quality rating of the other postretirement benefit assets fixed income security portfolio is investment grade with a weighted-average duration of approximately 5 years for 2013 and 2012.

The fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement of an asset.

Shares of the cash management funds are valued at fair value based on published market prices as of the close of business on the last business day of the year, which represents the net asset values of the shares held.

The fair values of equity securities traded on U.S. exchanges are derived from quoted market prices as of the close of business on the last business day of the year. The fair values of equity securities traded on foreign exchanges are also derived from quoted market prices as of the close of business on an active foreign exchange on the last business day of the year. However, the valuation requires translation of the foreign currency to U.S. dollars and this translation is considered an observable input to the valuation.

The fair value of all commingled investment funds are determined based on the net asset values per unit of each of the funds. The net asset values per unit represent the aggregate value of the funds assets at fair value less liabilities, divided by the number of units outstanding.

The fair value of fixed income securities, except U.S. Treasury notes and bonds, are determined using pricing models. These pricing models incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads for similar securities to determine fair value. The U.S. Treasury notes and bonds are valued at fair value based on closing prices on the last business day of the year reported in the active market in which the security is traded.

The investment contracts with insurance companies are valued at fair value by discounting the cash flow of a bond using a yield to maturity based on an investment grade index or comparable index with a similar maturity value, maturity period, and nominal coupon rate.

There have been no significant changes in the preceding valuation methodologies used at December 31, 2013 and 2012. Additionally, there were no transfers or reclassifications of investments between Level 1 and Level 2 from December 2012 to December 2013. If transfers between levels had occurred, the transfers would have been recognized as of the end of the period.

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Plan Benefit Payments and Employer Contributions

Following are the expected benefits to be paid by the plans. These estimates are based on the same assumptions previously discussed and reflect future service as appropriate. The actuarial assumptions are based on long-term expectations and include, but are not limited to, assumptions as to average expected retirement age and form of benefit payment. Actual benefit payments could differ significantly from expected benefit payments if near-term participant behaviors differ significantly from the actuarial assumptions.

	Pension Benefits		Other Postretirement Benefits
	(Millions)
2014	$	88	$	15
2015	96		15
2016	102		16
2017	103		16
2018	109		17
2019-2023	591		74

In 2014, we expect to contribute approximately $60 million to our tax-qualified pension plans and approximately $3 million to our nonqualified pension plans, for a total of approximately $63 million, and approximately $8 million to our other postretirement benefit plans.

Defined Contribution Plans

We also maintain defined contribution plans for the benefit of substantially all of our employees. Generally, plan participants may contribute a portion of their compensation on a pre-tax and after-tax basis in accordance with the plans’ guidelines. We match employees’ contributions up to certain limits. Our matching contributions charged to expense were $27 million in 2013, $25 million in 2012, and $28 million in 2011. Included in 2011 is $5 million in matching contributions for employees that supported WPX’s operations that were directly charged to WPX and included in Income (loss) from discontinued operations.

Note 10 – Inventories

	December 31,
	2013		2012
	(Millions)
Natural gas liquids, olefins, and natural gas in underground storage	$	111	$	97
Materials, supplies, and other	83		78
	$	194	$	175

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The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 11 – Property, Plant, and Equipment

	Estimated Useful Life  (1) (Years)	Depreciation Rates (1) (%)
			December 31,
			2013			2012
			(Millions)
Nonregulated:
Natural gas gathering and processing facilities	5 - 40		$	9,185		$	7,727
Construction in progress	Not applicable		3,123			1,997
Other	3 - 45		1,316			1,103
Regulated:
Natural gas transmission facilities		1.20 - 6.97	10,633			9,963
Construction in progress		Not applicable	273			337
Other		1.35 - 33.33	1,293			1,419
Total property, plant, and equipment, at cost			25,823			22,546
Accumulated depreciation and amortization			(7,613		)	(7,079		)
Property, plant, and equipment — net			$	18,210		$	15,467

__________

(1) Estimated useful life and depreciation rates are presented as of December 31, 2013. Depreciation rates for regulated assets are prescribed by the FERC.

Depreciation and amortization expense forProperty, plant, and equipment – net was $752 million in 2013, $712 million in 2012, and $658 million in 2011.

Regulated Property, plant, and equipment – net includes approximately $785 million and $825 million at December 31, 2013 and 2012, respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.

Asset Retirement Obligations

Our accrued obligations relate to underground storage caverns, offshore platforms, fractionation and compression facilities, gas gathering well connections and pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to restore land and remove surface equipment at gas processing, fractionation and compression facilities, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.

121

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The following table presents the significant changes to our asset retirement obligations (ARO), of which $497 million and $511 million are included in Other noncurrent liabilities with the remaining current portion in Accrued liabilities at December 31, 2013 and 2012, respectively.

	December 31,
	2013			2012
	(Millions)
Beginning balance	$	579		$	573
Liabilities incurred	8			8
Liabilities settled (1)	(31		)	(44		)
Accretion expense	53			43
Revisions (2)	(48		)	(1		)
Ending balance	$	561		$	579

______________

(1) For 2013 and 2012, liabilities settled include $25 million and $31 million, respectively, related to the abandonment of certain of Transco’s natural gas storage caverns that are associated with a leak in 2010.

(2) Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of the assets. The 2013 revision primarily reflects increases in the estimated remaining useful life of the assets. The 2012 revision primarily reflects a decrease in removal cost estimates. The 2013 and 2012 revisions also include increases of $9 million and $13 million, respectively, related to changes in the timing and method of abandonment on certain of Transco’s natural gas storage caverns that were associated with a leak in 2010.

Transco is entitled to collect in rates the amounts necessary to fund its ARO. All funds received for such retirements are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) Under its current rate settlement, Transco’s annual funding obligation is approximately $36 million, with installments to be deposited monthly.

Note 12 – Accrued Liabilities

	December 31,
	2013		2012
	(Millions)
Interest on debt	$	167	$	148
Employee costs	127		137
Estimated rate refund liability	98		—
Asset retirement obligations	64		68
Other, including other loss contingencies	341		275
	$	797	$	628

122

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 13 – Debt, Banking Arrangements, and Leases

Long-Term Debt

	December 31,
	2013			2012
	(Millions)
Unsecured:
Transco:
6.4% Notes due 2016	$	200		$	200
6.05% Notes due 2018	250			250
7.08% Debentures due 2026	8			8
7.25% Debentures due 2026	200			200
5.4% Notes due 2041	375			375
4.45% Notes due 2042	400			400
Northwest Pipeline:
7% Notes due 2016	175			175
5.95% Notes due 2017	185			185
6.05% Notes due 2018	250			250
7.125% Debentures due 2025	85			85
WPZ:
3.8% Notes due 2015	750			750
7.25% Notes due 2017	600			600
5.25% Notes due 2020	1,500			1,500
4.125% Notes due 2020	600			600
4% Notes due 2021	500			500
3.35% Notes due 2022	750			750
4.5% Notes due 2023	600			—
6.3% Notes due 2040	1,250			1,250
5.8% Notes due 2043	400			—
Credit facility loans	—			375
The Williams Companies, Inc.:
7.875% Notes due 2021	371			371
3.7% Notes due 2023	850			850
7.5% Debentures due 2031	339			339
7.75% Notes due 2031	252			252
8.75% Notes due 2032	445			445
Various — 5.5% to 10.25% Notes and Debentures due 2019 to 2033	55			57
Other, including secured capital lease obligations	1			2
Net unamortized debt discount	(37		)	(33		)
Total long-term debt, including current portion	11,354			10,736
Long-term debt due within one year	(1		)	(1		)
Long-term debt	$	11,353		$	10,735

Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, and incur additional debt. Default of these agreements could also restrict our ability to make certain distributions or repurchase equity.

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The following table presents aggregate minimum maturities of long-term debt (excluding net unamortized discount) for each of the next five years:

	December 31, 2013
	(Millions)
2014	$	—
2015	750
2016	375
2017	785
2018	500

Issuances and retirements

In November 2013, WPZ completed a public offering of $600 million of 4.5 percent senior unsecured notes due 2023 and $400 million of 5.8 percent senior unsecured notes due 2043. WPZ used the net proceeds to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes.

In December 2012, we completed a public offering of $850 million of 3.7 percent senior unsecured notes due 2023. We used the net proceeds to finance a portion of our investment in Access Midstream Partners.

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

In July 2012, Transco issued $400 million of 4.45 percent senior unsecured notes due 2042 to investors in a private debt placement. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in November 2012 and completed in December 2012. A portion of the proceeds from the issuance of these notes was used to repay Transco’s $325 million of 8.875 percent senior unsecured notes that matured on July 15, 2012.

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 December 31, 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 December 31, 2013, no letters of credit have been issued and no loans are outstanding on these credit facilities. We have issued letters of credit totaling $16 million as of December 31, 2013, under certain bilateral bank agreements.

Our significant financial covenants require our ratio of debt to EBITDA (each as defined in the credit facility) to be no greater than 4.5 to 1. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, we are required to maintain a ratio of debt to EBITDA of no greater than 5 to 1. At December 31, 2013, we are in compliance with these financial covenants.

WPZ's significant financial covenants require its ratio of debt to EBITDA (each as defined in the credit facility) to be no greater than 5 to 1. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, WPZ is required to maintain

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a ratio of debt to EBITDA of no greater than 5.5 to 1. In addition, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline. At December 31, 2013, WPZ is in compliance with these financial covenants.

The credit agreements governing our and WPZ’s respective credit facilities both contain the following terms and conditions:

• Each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.’s alternate base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus an applicable margin. The applicable borrower is required to pay a commitment fee (currently 0.225 percent for our agreement and 0.175 percent for the WPZ agreement) based on the unused portion of its respective credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings.

• Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, a borrower’s ability to merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, make investments, and allow any material change in the nature of its business.

• If an event of default with respect to a borrower occurs under its respective credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of any loans of the defaulting borrower under the respective credit facility agreement and exercise other rights and remedies.

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. We classify WPZ’s commercial paper outstanding in Current liabilities in the Consolidated Balance Sheet, as the outstanding notes at December 31, 2013, have maturity dates less than three months from the date of issuance. At December 31, 2013, WPZ has $225 million in Commercial paper outstanding at a weighted average interest rate of 0.42 percent.

Cash Payments for Interest (Net of Amounts Capitalized)

Cash payments for interest (net of amounts capitalized)were $472 million in 2013, $479 million in 2012, and $573 million in 2011.

Restricted Net Assets of Subsidiaries

We have considered the guidance in the Securities and Exchange Commission’s Regulation S-X related to restricted net assets of subsidiaries. In accordance with Rule 4-08(e) of Regulation S-X, we have determined that certain net assets of our subsidiaries are considered restricted under this guidance and exceed 25 percent of our consolidated net assets. Substantially all of these restricted net assets relate to the net assets of WPZ, which are technically considered restricted under this accounting rule due to terms within WPZ’s partnership agreement that govern the partnership’s assets. Our interest in WPZ’s net assets at December 31, 2013 was $6.5 billion.

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Leases-Lessee

The future minimum annual rentals under noncancelable operating leases, are payable as follows:

	December 31, 2013
	(Millions)
2014	$	53
2015	47
2016	43
2017	36
2018	30
Thereafter	123
Total	$	332

Under our right-of-way agreement with the Jicarilla Apache Nation, we make annual payments of approximately $8 million and an additional annual payment which varies depending on the prior year’s per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the agreement. Depending primarily on the per-unit NGL margins for any given year, the additional annual payments could exceed the fixed amount. This agreement expires March 31, 2029.

Total rent expense was $58 million in 2013, $56 million in 2012, and $49 million in 2011.

Note 14 – Stockholders' Equity

Cash dividends declared per common share were $1.4375, $1.19625 and $.775 for 2013, 2012, and 2011, respectively.

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

In December 2012, we issued approximately 53 million shares of common stock in a public offering at a price of $31 per share. We used the net proceeds of $1.6 billion to fund a portion of the purchase of an equity interest in ACMP. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets.)

We maintain a Stockholder Rights Plan, as amended and restated on September 21, 2004, and further amended May 18, 2007 and October 12, 2007, under which each outstanding share of our common stock has a right (as defined in the plan) attached. Under certain conditions, each right may be exercised to purchase, at an exercise price of $50 (subject to adjustment), one two-hundredth of a share of Series A Junior Participating Preferred Stock. The rights may be exercised only if an Acquiring Person acquires (or obtains the right to acquire) 15 percent or more of our common stock or commences an offer for 15 percent or more of our common stock. The plan contains a mechanism to divest of shares of common stock if such stock in excess of 14.9 percent was acquired inadvertently or without knowledge of the terms of the rights. The rights, which until exercised do not have voting rights, expire in September 2014 and may be redeemed at a price of $.01 per right prior to their expiration, or within a specified period of time after the occurrence of certain events. In the event a person becomes the owner of more than 15 percent of our common stock, each holder of a right (except an Acquiring Person) shall have the right to receive, upon exercise, our common stock having a value equal to two times the exercise price of the right. In the event we are engaged in a merger, business combination, or 50 percent or more of our assets, cash flow or earnings power is sold or transferred, each holder of a right (except an Acquiring Person) shall have the right to receive, upon exercise, common stock of the acquiring company having a value equal to two times the exercise price of the right.

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AOCI

The following table presents the changes in AOCI 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			(41		)	203			163
Amounts reclassified from accumulated othercomprehensive income (loss)	(1		)	—			36			35
Other comprehensive income (loss)	—			(41		)	239			198
Balance at December 31, 2013	$	(1	)	$	128		$	(291	)	$	(164	)

Reclassifications out of AOCI are presented in the following table by component for the year ended December 31, 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	(3		)	Note 9 – Employee Benefit Plans
Amortization of actuarial (gain) loss included in net periodic benefit cost	61			Note 9 – Employee Benefit Plans
Total pension and other postretirement benefits	58
Reclassifications before income tax	57
Income tax benefit	(22		)	Provision (benefit) for income taxes
Reclassifications during the period	$	35

Note 15 – Stock-Based Compensation

Plan Information

On May 17, 2007, our stockholders approved a plan that provides common-stock-based awards to both employees and nonmanagement directors and reserved 19 million new shares for issuance. On May 20, 2010, our stockholders approved an amendment and restatement of the 2007 plan to increase by 11 million the number of new shares authorized for making awards under the plan, among other changes. The plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. At December 31, 2013, 24 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 14 million shares were available for future grants.

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Additionally, on May 17, 2007, our stockholders approved an Employee Stock Purchase Plan (ESPP) which authorizes up to 2 million new shares of our common stock to be available for sale under the plan. The ESPP enables eligible participants to purchase our common stock through payroll deductions not exceeding an annual amount of $15,000 per participant. The ESPP provides for offering periods during which shares may be purchased and continues until the earliest of (1) the Board of Directors terminates the ESPP, (2) the sale of all shares available under the ESPP, or (3) the tenth anniversary of the date the Plan was approved by the stockholders. Offering periods are from January through June and from July through December. Generally, all employees are eligible to participate in the ESPP, with the exception of executives and international employees. The number of shares eligible for an employee to purchase during each offering period is limited to 750 shares. The purchase price of the stock is 85 percent of the lower closing price of either the first or the last day of the offering period. The ESPP requires a one-year holding period before the stock can be sold. Employees purchased 203 thousand shares at an average price of $27.62 per share during 2013. Approximately 413 thousand shares were available for purchase under the ESPP at December 31, 2013.

Total stock-based compensation expense for the years ended December 31, 2013, 2012, and 2011 was $37 million, $36 million, and $52 million, respectively, of which $18 million is included in Income (loss) from discontinued operations for 2011. Total income tax benefit recognized related to the total stock-based compensation expense for the years ended December 31, 2013, 2012, and 2011 was $14 million, $13 million, and $19 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2013, was $44 million, which does not include the effect of estimated forfeitures of $1 million. This amount is comprised of $4 million related to stock options and $40 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.8 years.

Stock Options

Stock options are valued at the date of award, which does not precede the approval date. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant. Stock options generally expire ten years after the grant.

The following summary reflects stock option activity and related information for the year ended December 31, 2013:

Stock Options	Options		Weighted- Average Exercise Price		Aggregate Intrinsic Value
	(Millions)				(Millions)
Outstanding at December 31, 2012	6.9		$	19.10
Granted	0.9		$	33.57
Exercised	(1.1	)	$	13.34
Outstanding at December 31, 2013	6.7		$	21.82	$	112
Exercisable at December 31, 2013	5.0		$	18.70	$	98

The total intrinsic value of options exercised during the years ended December 31, 2013, 2012, and 2011 was $23 million, $69 million, and $55 million, respectively; and the tax benefit realized was $9 million, $25 million, and $21 million, respectively. Cash received from stock option exercises was $13 million, $50 million, and $45 million during 2013, 2012, and 2011, respectively. The weighted-average remaining contractual life for stock options outstanding and exercisable at December 31, 2013, was 5.1 years and 3.9 years, respectively.

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The estimated fair value at date of grant of options for our common stock granted in each respective year, using the Black-Scholes option pricing model, is as follows:

	2013			2012			2011
Weighted-average grant date fair value of options for our common stock granted during the year, per share	$	5.94		$	5.65		$	6.28
Weighted-average assumptions:
Dividend yield	4.3		%	3.7		%	3.6		%
Volatility	29.7		%	30.0		%	34.6		%
Risk-free interest rate	1.4		%	1.3		%	2.8		%
Expected life (years)	6.5			6.5			6.5

The expected dividend yield is based on the 2013 dividend forecast and the grant-date market price of our stock. As a result of the 2011 spin-off of WPX, the historical volatility of our stock is not expected to be as representative of expected future volatility. Expected volatility is now based on the average of our peer group 10-year historical volatility adjusted by a ratio of our implied volatility to the average of our peer group’s implied volatility. The adjustment is made because the difference in implied volatility between our peer group and us may indicate that we are expected to be more volatile than our peer group average. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience.

Nonvested Restricted Stock Units

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2013.

Restricted Stock Units Outstanding	Shares		Weighted- Average Fair Value*
	(Millions)
Nonvested at December 31, 2012	3.9		$	22.49
Granted	1.2		$	30.43
Forfeited	(0.1	)	$	27.27
Vested	(1.5	)	$	17.82
Nonvested at December 31, 2013	3.5		$	27.16

______________

* Performance-based shares are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other shares are valued at the grant-date market price or the grant-date market price less dividends projected to be paid over the vesting period. Restricted stock units generally vest after three years.

Value of Restricted Stock Units	2013		2012		2011
Weighted-average grant date fair value of restricted stock units granted during the year, per share	$	30.43	$	20.61	$	23.31
Total fair value of restricted stock units vested during the year ($’s in millions)	$	27	$	22	$	35

Performance-based shares granted under the Plan represent 32 percent of nonvested restricted stock units outstanding at December 31, 2013. These grants may be earned at the end of a three-year period based on actual performance against a performance target. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.

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Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk

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 December 31, 2013:
Measured on a recurring basis:
ARO Trust investments	$	33		$	33		$	33	$	—		$	—
Energy derivatives assets not designated as hedging instruments	3			3			—		—			3
Energy derivatives liabilities not designated as hedging instruments	(3		)	(3		)	—		(1		)	(2		)
Additional disclosures:
Notes receivable and other	77			140			1		6			133
Long-term debt (1)	(11,353		)	(11,971		)	—		(11,971		)	—
Guarantee	(32		)	(29		)	—		(29		)	—
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 (1)	(10,734		)	(12,388		)	—		(12,388		)	—
Guarantee	(33		)	(31		)	—		(31		)	—

________________

(1) Excludes capital leases

Fair Value Methods

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

Assets and liabilities measured at fair value on a recurring basis

ARO Trust investments:  Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust 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

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in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

Energy derivatives:  Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring 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 years ended December 31, 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 4 – 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 $97 million at December 31, 2013. The carrying value of this receivable is $35 million at December 31, 2013. The current and noncurrent portions are reported in Accounts and notes receivable, net and Regulatory assets, deferred charges, and other, respectively, in the Consolidated Balance Sheet.

Notes receivable and other also includes a receivable from our former affiliate, WPX (see Note 17 – Contingent Liabilities and Commitments) and other notes receivable. The disclosed fair value of these receivables is primarily determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion is reported in Accounts and notes receivable, net and the noncurrent portion is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet.

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

Guarantee:  The guarantee represented in the table consists of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042.

To estimate the disclosed fair value of the guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. This guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet.

Guarantees

We are required by our revolving credit agreements to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax

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regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.

Regarding our previously described guarantee of WilTel’s lease performance, the maximum potential exposure is approximately $35 million, and $36 million at December 31, 2013 and 2012, respectively. 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 $69 million at December 31, 2013. Our recorded liability for these guarantees, which considers our estimate of the fair value of the guarantees, is insignificant.

Concentration of Credit Risk

Cash equivalents

Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Accounts and notes receivable

The following table summarizes concentration of receivables, net of allowances.

	December 31,
	2013		2012
	(Millions)
NGLs, natural gas, and related products and services	$	341	$	411
Transportation of natural gas and related products	193		170
Income tax receivable	74		68
Other	66		39
Total	$	674	$	688

Customers include producers, distribution companies, industrial users, gas marketers and pipelines primarily located in the continental United States and Canada. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

Revenues

In 2013, 2012, and 2011, we had one customer in our Williams Partners segment that accounted for 9 percent, 14 percent and 17 percent of our consolidated revenues, respectively.

Note 17 – Contingent Liabilities and Commitments

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 FERC. WPX has entered into settlements with

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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. On December 23, 2013, the parties submitted their settlement to the FERC for regulatory approval. The settlement will resolve most of WPX’s legal issues arising from the 2000-2001 California Energy Crisis. We currently have a net receivable from WPX related to these matters.

Reporting of natural gas-related information to trade publications

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

In 2011, the Nevada district court granted WPX’s joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs appealed the court’s ruling and on April 10, 2013, the Ninth Circuit Court of Appeals reversed the district court and remanded the cases to the district court to permit the plaintiffs to pursue their state antitrust claims for natural gas sales that were not subject to FERC jurisdiction under the Natural Gas Act. On August 26, 2013, WPX and the other defendants filed their petition for a writ of certiorari with the U.S. Supreme Court. Because of the uncertainty around the remaining pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time. However, it is reasonably possible that the ultimate resolution of these items and our related indemnification obligation could result in future charges that may be material to our results of operations.

Other Legal Matters

Geismar Incident

As a result of the previously discussed Geismar Incident, there were two fatalities and numerous individuals (including employees and contractors) reported injuries, which varied from minor to serious. WPZ is cooperating with the Chemical Safety Board, and the U.S. Environmental Protection Agency (EPA) regarding their investigations of the Geismar Incident. On October 21, 2013, the EPA issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. We and the EPA continue to discuss such preliminary determinations, and the EPA could issue penalties pertaining to final determinations. On December 11, 2013, the Occupational Safety and Health Administration (OSHA) issued Citations for the June 13, 2013 incident, which included a Notice of Penalty for $99,000. Although we and OSHA continue settlement negotiations, we are contesting the citation. On June 28, 2013, the Louisiana Department of Environmental Quality (LDEQ) issued a Consolidated Compliance Order & Notice of Potential Penalty to Williams Olefins, L.L.C. that consolidates claims of unpermitted emissions and other deviations under the Clean Air Act that the parties had been negotiating since 2010 and alleged unpermitted emissions arising from the Geismar Incident. Negotiations with the LDEQ are ongoing. Any potential fines and penalties from these agencies would not be covered by our insurance policy. Additionally, multiple lawsuits, including class actions for alleged offsite impacts, property damage, and personal injury, have been filed against various of our subsidiaries.

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

Gulf Liquids litigation

Gulf Liquids, one of our subsidiaries, contracted with Gulsby Engineering Inc. (Gulsby) and Gulsby-Bay (a joint venture between Gulsby and Bay Ltd.) for the construction of certain gas processing plants in Louisiana. National American Insurance Company (NAICO) and American Home Assurance Company provided payment and performance bonds for the projects. In 2001, the contractors and sureties filed multiple cases in Louisiana and Texas against Gulf Liquids and us.

In 2006, at the conclusion of the consolidated trial of the asserted contract and tort claims, the jury returned its actual and punitive damages verdict against us and Gulf Liquids. 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 seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination.

In 2011, we and FHRA settled the James West claim. We and FHRA subsequently filed motions for summary judgment on the other’s claims. On November 5, 2013, the court ruled that the applicable statute of limitations bars all FHRA’s claims against us and dismissed those claims with prejudice. FHRA has asked the court to reconsider and clarify its ruling, and we anticipate that FHRA will appeal the court’s decision.

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

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Notes to Consolidated Financial Statements – (Continued)

Independent of the litigation matter described in the preceding paragraphs, the Alaska Department of Environmental Conservation (ADEC) indicated that it views FHRA and us as responsible parties. During the first quarter of 2013 and again on December 23, 2013, ADEC informed FHRA and us that 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

On August 31, 2012, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceedings. The new rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, Transco filed a stipulation and agreement with the FERC proposing to resolve all issues in this proceeding without the need for a hearing (Agreement). On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds of $98 million, in Accrued liabilities, which we believe is adequate for required refunds as of December 31, 2013, under the Agreement. Refunds will be made on or before April 30, 2014.

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2013, we have accrued liabilities totaling $47 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered and the final cleanup standards mandated by the EPA and other governmental authorities.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, one hour nitrogen dioxide emission limits, and new air quality standards impacting storage vessels, pressure valves, and compressors. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

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 December 31, 2013, we have accrued liabilities of $13 million for these costs. We expect that these costs will be recoverable through rates.

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Notes to Consolidated Financial Statements – (Continued)

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 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 December 31, 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 December 31, 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.

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.

Commitments

Commitments for construction and acquisition of property, plant, and equipment are approximately $1.5 billion at December 31, 2013.

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Notes to Consolidated Financial Statements – (Continued)

Note 18 – 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 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

Our segment presentation of Williams Partners is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions associated with this master limited partnership structure. WPZ maintains a capital and cash management structure that is separate from ours. WPZ is self-funding and maintains its own lines of bank credit and cash management accounts. These factors, coupled with a different cost of capital from our other businesses, serve to differentiate the management of this entity as a whole.

Our segment presentation of Access Midstream Partners reflects the significant size of this investment and the economic opportunities it represents in major unconventional producing areas that add diversity to our current asset base.

Performance Measurement

We currently evaluate segment operating performance based upon Segment profit (loss) from operations, which includes Segment revenues from external and internal customers, segment costs and expenses, Equity earnings (losses) and Income (loss) from investments. General corporate expenses represent Selling, general, and administrative expenses that are not allocated to our segments. The accounting policies of the segments are the same as those described in Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies. Intersegment revenues are generally accounted for at current market prices as if the sales were to unaffiliated third parties.

The following geographic area data includes Revenues from external customers based on product shipment origin and Long-lived assets based upon physical location.

			United States		Canada		Total
			(Millions)
Revenues from external customers:
	2013	$	6,703	$	157	$	6,860
	2012		7,335		151		7,486
	2011		7,728		202		7,930
Long-lived assets:
	2013	$	19,260	$	1,240	$	20,500
	2012		16,940		880		17,820
	2011		12,041		583		12,624

Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets.

As discussed in Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 4 – Discontinued Operations, our former exploration and production business was spun-off on December 31, 2011 and has been reported as discontinued operations in all prior periods presented. Revenues derived from intercompany sales to our former exploration and production business, previously reported as internal, are now shown as external. These sales were $310 million for the year ended 2011. In addition, costs attributable to activities with our former exploration and production business, previously reported as internal, are now shown as external. Such costs were $845 million for the year ended 2011. We continue to recognize revenue as we provide certain gathering, processing, and treating services to WPX under long term agreements.

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Notes to Consolidated Financial Statements – (Continued)

The following table reflects the reconciliation of Segment revenues and Segment profit (loss) to Total revenues and Operating income (loss) as reported in the Consolidated Statement of Income and Other financial information related to Long-lived assets.

	Williams Partners		Williams NGL & Petchem Services			Access Midstream Partners		Other			Eliminations			Total
	(Millions)
2013
Segment revenues:
Service revenues
External	$	2,910	$	4		$	—	$	25		$	—		$	2,939
Internal	—		—			—		11			(11		)	—
Total service revenues	2,910		4			—		36			(11		)	2,939
Product sales
External	3,775		146			—		—			—			3,921
Internal	—		123			—		—			(123		)	—
Total product sales	3,775		269			—		—			(123		)	3,921
Total revenues	$	6,685	$	273		$	—	$	36		$	(134	)	$	6,860
Segment profit (loss)	$	1,606	$	38		$	61	$	(4	)				$	1,701
Less:
Equity earnings (losses)	104		—			30		—						134
Income (loss) from investments	—		(3		)	31		—						28
Segment operating income (loss)	$	1,502	$	41		$	—	$	(4	)				1,539
General corporate expenses														(164		)
Operating income (loss)														$	1,375
Other financial information:
Additions to long-lived assets	$	3,055	$	649		$	—	$	27		$	—		$	3,731
Depreciation and amortization	758		33			—		24			—			815
2012
Segment revenues:
Service revenues
External	$	2,709	$	5		$	—	$	15		$	—		$	2,729
Internal	—		—			—		12			(12		)	—
Total service revenues	2,709		5			—		27			(12		)	2,729
Product sales
External	4,611		146			—		—			—			4,757
Internal	—		128			—		—			(128		)	—
Total product sales	4,611		274			—		—			(128		)	4,757
Total revenues	$	7,320	$	279		$	—	$	27		$	(140	)	$	7,486
Segment profit (loss)	$	1,812	$	99		$	—	$	49					$	1,960
Less:
Equity earnings (losses)	111		—			—		—						111
Income (loss) from investments	—		(4		)	—		53						49
Segment operating income (loss)	$	1,701	$	103		$	—	$	(4	)				1,800
General corporate expenses														(188		)
Operating income (loss)														$	1,612
Other financial information:
Additions to long-lived assets	$	5,562	$	425		$	—	$	31		$	—		$	6,018
Depreciation and amortization	714		20			—		22			—			756

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Notes to Consolidated Financial Statements – (Continued)

	Williams Partners		Williams NGL & Petchem Services			Access Midstream Partners		Other		Eliminations			Total
	(Millions)
2011
Segment revenues:
Service revenues
External	$	2,517	$	1		$	—	$	14	$	—		$	2,532
Internal	—		—			—		11		(11		)	—
Total service revenues	2,517		1			—		25		(11		)	2,532
Product sales
External	5,197		201			—		—		—			5,398
Internal	—		139			—		—		(139		)	—
Total product sales	5,197		340			—		—		(139		)	5,398
Total revenues	$	7,714	$	341		$	—	$	25	$	(150	)	$	7,930
Segment profit (loss)	$	2,035	$	157		$	—	$	24				$	2,216
Less:
Equity earnings (losses)	142		—			—		13					155
Income (loss) from investments	—		(4		)	—		11					7
Segment operating income (loss)	$	1,893	$	161		$	—	$	—				2,054
General corporate expenses													(187		)
Operating income (loss)													$	1,867
Other financial information:
Additions to long-lived assets	$	1,273	$	211		$	—	$	46	$	—		$	1,530
Depreciation and amortization	621		16			—		24		—			661

The following table reflects Total assets and Equity method investments by reportable segments:

	Total Assets						Equity Method Investments
	December 31, 2013			December 31, 2012			December 31, 2013		December 31, 2012
	(Millions)
Williams Partners	$	22,358		$	19,709		$	2,187	$	1,800
Williams NGL & Petchem Services	1,711			1,134			12		—
Access Midstream Partners	2,161			2,187			2,161		2,187
Other	1,625			1,782			—		—
Eliminations	(713		)	(485		)	—		—
Total	$	27,142		$	24,327		$	4,360	$	3,987

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Notes to Consolidated Financial Statements – (Continued)

Note 19 – Subsequent Events

Commercial Paper Outstanding Balance

As of February 25, 2014, $900 million is outstanding under WPZ’s commercial paper program.

Canada Dropdown

In February 2014, we agreed to contribute certain Canadian operations to WPZ for total consideration valued at approximately $1.2 billion. The transaction is expected to close in February 2014. Upon closing we expect to receive $25 million of cash, 25,577,521 Class D limited-partner units, and an increase in our general partner capital account that will allow us to maintain our 2 percent general partner interest. In lieu of cash distributions, the Class D units will receive quarterly distributions of additional paid-in-kind Class D units, all of which will be convertible to common units at a future date. The agreement also provides that WPZ can issue additional Class D units to us on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions.

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Quarterly Financial Data

(Unaudited)

Summarized quarterly financial data are as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(Millions, except per-share amounts)
2013
Revenues	$	1,810	$	1,767	$	1,623	$	1,660
Product costs	790		801		710		726
Income (loss) from continuing operations	231		200		198		50
Net income (loss)	230		192		197		49
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations	162		149		143		(13		)
Net income (loss)	161		142		141		(14		)
Basic earnings (loss) per common share:
Income (loss) from continuing operations	.24		.22		.21		(.02		)
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	.23		.22		.20		(.02		)
2012
Revenues	$	2,019	$	1,846	$	1,752	$	1,869
Product costs	957		900		771		868
Income (loss) from continuing operations	359		166		200		204
Net income (loss)	495		165		203		202
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations	287		133		152		151
Net income (loss)	423		132		155		149
Basic earnings (loss) per common share:
Income (loss) from continuing operations	.48		.21		.25		.23
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	.47		.21		.25		.23

The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the average number of common shares outstanding and rounding.

2013

Net income for fourth-quarter 2013 includes the following pre-tax items:

• $20 million write-off of an abandoned project at Williams NGL & Petchem Services (see Note 6 – Other Income and Expenses);

• $16 million accrued loss associated with a settlement in principle of a producer claim against us at Williams Partners (see Note 6 – Other Income and Expenses);

• $13 million interest income on the note receivable related to the sale of certain former Venezuela assets (see Note 5 – Investing Activities);

• $14 million in expenses associated with the Geismar Incident at Williams Partners (see Note 6 – Other Income and Expenses).

Net income for fourth-quarter 2013 also includes $99 million of deferred income tax expense incurred on undistributed earnings of our foreign operations that are no longer considered permanently reinvested (see Note 7 – Provision (Benefit) for Income Taxes).

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Quarterly Financial Data – (Continued)

(Unaudited)

Net income for third-quarter 2013 includes the following pre-tax items:

• $9 million accrued loss associated with a contingent liability related to a producer claim against us at Williams Partners (see Note 6 – Other Income and Expenses);

• $50 million gain associated with insurance recoveries related to the Geismar Incident at Williams Partners (see Note 6 – Other Income and Expenses);

• $11 million of interest income associated with a receivable related to the sale of certain former Venezuela assets (see Note 5 – Investing Activities).

Net income for second-quarter 2013 includes the following pre-tax items:

• $12 million of income related to an insurance recovery associated with the Eminence abandonment regulatory asset that will not be recovered through rates at Williams Partners (see Note 6 – Other Income and Expenses);

• $26 million gain resulting from Access Midstream Partners' equity issuance (see Note 5 – Investing Activities);

• $13 million of interest income associated with a receivable related to the sale of certain former Venezuela assets (see Note 5 – Investing Activities);

• $12 million charge resulting from an unfavorable ruling associated with our former Alaska refinery related to the Trans-Alaska Pipeline System Quality Bank (see summarized results of discontinued operations at Note 4 – Discontinued Operations).

Net income for first-quarter 2013 includes $13 million of interest income associated with a receivable related to the sale of certain former Venezuela assets (see Note 5 – Investing Activities).

2012

Net income for fourth-quarter 2012 includes the following pre-tax items:

• $18 million related to the reversal of project feasibility costs from expense to capital at Williams Partners (see Note 6 – Other Income and Expenses);

• $12 million of reorganization-related costs including engaging a consulting firm in 2012 to assist in better aligning resources to support our business strategy following the spin-off of WPX (see Note 6 – Other Income and Expenses).

Net income for second-quarter 2012 includes $21 million of Caiman and Laser acquisition and transition-related costs at Williams Partners (see Note 2 – Acquisitions, Goodwill, and Other Intangible Assets).

Net income for first-quarter 2012 includes the following pre-tax items:

• $63 million of income, including $10 million of interest, related to the sale of our 50 percent interest in Accroven (see Note 5 – Investing Activities);

• $144 million of gain on reconsolidation related to our majority ownership in the Wilpro entities (see summarized results of discontinued operations at Note 4 – Discontinued Operations).

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The Williams Companies, Inc.

Schedule I — Condensed Financial Information of Registrant

Statement of Comprehensive Income (Parent)

	Years Ended December 31,
	2013			2012			2011
	(Millions, except per-share amounts)
Equity in earnings of consolidated subsidiaries	$	1,564		$	1,895		$	1,962
Equity earnings from investment in Access Midstream Partners	30			—			—
Interest incurred — external	(156		)	(128		)	(186		)
Interest incurred — affiliate	(722		)	(816		)	(622		)
Interest income — affiliate	71			84			84
Early debt retirement costs	—			—			(271		)
Other income (expense) — net	32			3			(45		)
Income from continuing operations before income taxes	819			1,038			922
Provision for income taxes	378			315			119
Income (loss) from continuing operations	441			723			803
Income (loss) from discontinued operations	(11		)	136			(427		)
Net income (loss)	$	430		$	859		$	376
Basic earnings (loss) per common share:
Income (loss) from continuing operations	$	.65		$	1.17		$	1.36
Income (loss) from discontinued operations	(.02		)	.22			(.72		)
Net income (loss)	$	.63		$	1.39		$	.64
Weighted-average shares (thousands)	682,948			619,792			588,553
Diluted earnings (loss) per common share:
Income (loss) from continuing operations	$	.64		$	1.15		$	1.34
Income (loss) from discontinued operations	(.02		)	.22			(.71		)
Net income (loss)	$	.62		$	1.37		$	.63
Weighted-average shares (thousands)	687,185			625,486			598,175
Other comprehensive income (loss):
Equity in other comprehensive income (loss) of consolidated subsidiaries	$	(41	)	$	21		$	35
Other comprehensive income (loss) attributable to The Williams Companies, Inc.	239			6			(123		)
Other comprehensive income (loss)	198			27			(88		)
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	628		$	886		$	288

See accompanying notes.

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The Williams Companies, Inc.

Schedule I — Condensed Financial Information of Registrant – (Continued)

Balance Sheet (Parent)

	December 31,
	2013		2012
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	282	$	340
Other current assets and deferred charges	167		229
Total current assets	449		569
Investments in and advances to consolidated subsidiaries	19,162		16,686
Investment in Access Midstream Partners	2,161		2,187
Property, plant, and, equipment — net	68		62
Other noncurrent assets	34		117
Total assets	$	21,874	$	19,621
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	26	$	29
Long-term debt due within one year	1		1
Other current liabilities	147		122
Total current liabilities	174		152
Long-term debt	2,296		2,298
Notes payable — affiliates	10,830		8,938
Pension, other postretirement, and other noncurrent liabilities	282		712
Deferred income taxes	3,428		2,769
Contingent liabilities and commitments
Equity:
Common stock	718		716
Other stockholders’ equity	4,146		4,036
Total stockholders’ equity	4,864		4,752
Total liabilities and stockholders’ equity	$	21,874	$	19,621

See accompanying notes.

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The Williams Companies, Inc.

Schedule I — Condensed Financial Information of Registrant – (Continued)

Statement of Cash Flows (Parent)

	Years Ended December 31,
	2013			2012			2011
	(Millions)
NET CASH FLOWS PROVIDED (USED) BY OPERATING ACTIVITIES	$	19		$	(11	)	$	(286	)
FINANCING ACTIVITIES:
Proceeds from long-term debt	—			848			75
Payments of long-term debt	(1		)	(28		)	(871		)
Changes in notes payable to affiliates	1,892			520			(590		)
Tax benefit of stock-based awards	19			44			22
Premiums paid on early debt retirement	—			—			(254		)
Proceeds from issuance of common stock	18			2,550			49
Dividends paid	(982		)	(742		)	(457		)
Other — net	(3		)	(7		)	(5		)
Net cash provided (used) by financing activities	943			3,185			(2,031		)
INVESTING ACTIVITIES:
Capital expenditures	(23		)	(18		)	(28		)
Purchase of investment in Access Midstream Partners	(4		)	(2,179		)	—
Changes in investments in and advances to consolidated subsidiaries	(985		)	(953		)	2,553
Other — net	(8		)	24			(18		)
Net cash provided (used) by investing activities	(1,020		)	(3,126		)	2,507
Increase (decrease) in cash and cash equivalents	(58		)	48			190
Cash and cash equivalents at beginning of year	340			292			102
Cash and cash equivalents at end of year	$	282		$	340		$	292

See accompanying notes.

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Schedule I — Condensed Financial Information of Registrant – (Continued)

Notes to Financial Information (Parent)

Note 1. Guarantees

In addition to the guarantees disclosed in the accompanying consolidated financial statements in Item 8, we have financially guaranteed the performance of certain consolidated subsidiaries. The duration of these guarantees varies and we estimate the maximum undiscounted potential future payment obligation related to these guarantees as of December 31, 2013, is approximately $3.8 billion.

Note 2. Cash Dividends Received

We receive dividends and distributions either directly from our subsidiaries or indirectly through dividends received by subsidiaries and subsequent transfers of cash to us through our corporate cash management system. The total of such receipts ultimately related to dividends and distributions for the years ended December 31, 2013, 2012 and 2011 was approximately $1.5 billion, $1.1 billion, and $1.2 billion, respectively.

146

The Williams Companies, Inc.

Schedule II — Valuation and Qualifying Accounts

			Additions
	Beginning Balance		Charged (Credited) To Costs and Expenses			Other		Deductions			Ending Balance
	(Millions)
2013
Allowance for doubtful accounts — accounts and notes receivable (1)	$	—	$	—		$	—	$	—		$	—
Deferred tax asset valuation allowance (1)	144		37			—		—			181
2012
Allowance for doubtful accounts — accounts and notes receivable (1)	1		—			—		1		(3)	—
Deferred tax asset valuation allowance (1)	145		(1		)	—		—			144
2011
Allowance for doubtful accounts — accounts and notes receivable (2)	15		1			—		15		(4)	1
Deferred tax asset valuation allowance (5)	249		(33		)	—		71		(4)	145

_______________________

(1)    Deducted from related assets.

(2)    Deducted from related assets, primarily included in assets of discontinued operations.

(3)    Represents balances written off, reclassifications, and recoveries.

(4)    Includes balance deductions due to the spin-off of our exploration and production business on December 31,

2011.

(5)    Deducted primarily from related assets, with a portion included in assets of discontinued operations.

147

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

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

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Controls Over Financial Reporting

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

Management’s Annual Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a - 15(f) and 15d - 15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

148

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2013, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (1992). Based on our assessment, we concluded that, as of December 31, 2013, our internal control over financial reporting was effective.

Ernst & Young LLP, our independent registered public accounting firm, has audited our internal control over financial reporting, as stated in their report which is included in this Annual Report on Form 10-K.

149

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

The Board of Directors and Stockholders of

The Williams Companies, Inc.

We have audited The Williams Companies, Inc.’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the “COSO criteria”). The Williams Companies, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, The Williams Companies, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of The Williams Companies, Inc. as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2013, and our report dated February 26, 2014, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 26, 2014

150

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information regarding our directors and nominees for director required by Item 401 of Regulation S-K will be presented under the heading “Proposal 1 — Election of Directors” in our Proxy Statement prepared for the solicitation of proxies in connection with our Annual Meeting of Stockholders to be held May 22, 2014 (Proxy Statement), which information is incorporated by reference herein.

Information regarding our executive officers required by Item 401(b) of Regulation S-K is presented at the end of Part I herein and captioned “Executive Officers of the Registrant” as permitted by General Instruction G(3) to Form 10‑K and Instruction 3 to Item 401(b) of Regulation S-K.

Information required by Item 405 of Regulation S-K will be included under the heading “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement, which information is incorporated by reference herein.

Information required by paragraphs (c)(3), (d)(4) and (d)(5) of Item 407 of Regulation S-K will be included under the heading “Questions and Answers About the Annual Meeting and Voting” and “Corporate Governance and Board Matters” in our Proxy Statement, which information is incorporated by reference herein.

We have adopted a Code of Ethics for Senior Officers that applies to our Chief Executive Officer, Chief Financial Officer, and Controller, or persons performing similar functions. The Code of Ethics for Senior Officers, together with our Corporate Governance Guidelines, the charters for each of our board committees, and our Code of Business Conduct applicable to all employees are available on our Internet website at www.williams.com. We will provide, free of charge, a copy of our Code of Ethics or any of our other corporate documents listed above upon written request to our Corporate Secretary at Williams, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172. We intend to disclose any amendments to or waivers of the Code of Ethics on behalf of our Chief Executive Officer, Chief Financial Officer, Controller, and persons performing similar functions on our Internet website at www.williams.com under the Investor Relations caption, promptly following the date of any such amendment or waiver.

Item 11. Executive Compensation

The information required by Item 402 and paragraphs (e)(4) and (e)(5) of Item 407 of Regulation S-K regarding executive compensation will be presented under the headings “Compensation Discussion and Analysis,” “Executive Compensation and Other Information,” “Compensation of Directors,” “Compensation Committee Report on Executive Compensation,” and “Compensation Committee Interlocks and Insider Participation” in our Proxy Statement, which information is incorporated by reference herein. Notwithstanding the foregoing, the information provided under the heading “Compensation Committee Report on Executive Compensation” in our Proxy Statement is furnished and shall not be deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, is not subject to the liabilities of that section and is not deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information regarding securities authorized for issuance under equity compensation plans required by Item 201(d) of Regulation S-K and the security ownership of certain beneficial owners and management required by Item 403 of Regulation S-K will be presented under the headings “Equity Compensation Stock Plans” and “Security Ownership of Certain Beneficial Owners and Management” in our Proxy Statement, which information is incorporated by reference herein.

151

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information regarding certain relationships and related transactions required by Item 404 and Item 407(a) of Regulation S-K will be presented under the heading “Corporate Governance and Board Matters” in our Proxy Statement, which information is incorporated by reference herein.

Item 14. Principal Accountant Fees and Services

The information regarding our principal accounting fees and services required by Item 9(e) of Schedule 14A will be presented under the heading “Principal Accountant Fees and Services” in Proposal 4 Ratification of the Appointment of Independent Auditors of our Proxy Statement, which information is incorporated by reference herein.

152

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) 1 and 2.

	Page
Covered by report of independent auditors:
Consolidated statement of income for each year in the three-year period ended December 31, 2013	80
Consolidated statement of comprehensive income for each year in the three-year period ended December 31, 2013	81
Consolidated balance sheet at December 31, 2013 and 2012	82
Consolidated statement of changes in equity for each year in the three-year period ended December  31, 2013	83
Consolidated statement of cash flows for each year in the three-year period ended December 31, 2013	84
Notes to consolidated financial statements	85
Schedule for each year in the three-year period ended December 31, 2013:
I — Condensed financial information of registrant	143
II — Valuation and qualifying accounts	147
Not covered by report of independent auditors:
Quarterly financial data (unaudited)	141

All other schedules have been omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and notes thereto.

(a) 3 and (b). The exhibits listed below are filed as part of this annual report.

INDEX TO EXHIBITS

Exhibit No.		Description
3.1	—	Amended and Restated Certificate of Incorporation, as supplemented (filed on May 26, 2010 as Exhibit 3.1 to The Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.2	—	By-Laws (filed on May 26, 2010 as Exhibit 3.2 to The Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.1	—	Senior Indenture dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank, Trustee (filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline’s registration statement on Form S-3 (File No. 033-62639) and incorporated herein by reference).
4.2	—	Senior Indenture dated as of July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s registration statement on Form S-3 (File No. 333-02155) and incorporated herein by reference).
4.3	—	Senior Indenture dated February 25, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed February 25, 1997 as Exhibit 4.4.1 to MAPCO Inc.’s Amendment No. 1 to registration statement on Form S-3 (File No. 333-20837) and incorporated herein by reference).

153

Exhibit No.		Description
4.4	—	Supplemental Indenture No. 1 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(o) to MAPCO Inc.’s annual report on Form 10-K for the fiscal year ended December 31, 1997 (File No. 001-05254) and incorporated herein by reference).
4.5	—	Supplemental Indenture No. 2 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(p) to MAPCO Inc.’s annual report on Form 10-K for the fiscal year ended December 31, 1997 (File No. 001-05254) and incorporated herein by reference).
4.6	—	Supplemental Indenture No. 3 dated March 31, 1998, among MAPCO Inc., Williams Holdings of Delaware, Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(j) to Williams Holdings of Delaware, Inc.’s annual report on Form 10-K for the fiscal year ended December 31, 1998 (File No. 000-20555) and incorporated herein by reference).
4.7	—	Supplemental Indenture No. 4 dated as of June 30, 1999, among Williams Holdings of Delaware, Inc., Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on March 28, 2000 as Exhibit 4(q) to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
4.8	—	Fifth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed on March 12, 2001 as Exhibit 4(k) to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
4.9	—	Seventh Supplemental Indenture dated March 19, 2002, between The Williams Companies, Inc. as Issuer and Bank One Trust Company, National Association, as Trustee (filed on May 9, 2002 as Exhibit 4.1 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
4.10	—	Indenture dated as of May 28, 2003, by and between The Williams Companies, Inc. and JPMorgan Chase Bank, as Trustee for the issuance of the 5.50% Junior Subordinated Convertible Debentures due 2033 (filed on August 12, 2003 as Exhibit 4.2 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
4.11	—	Indenture dated as of April 11, 2006, between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.12	—	Indenture dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
4.13	—	Indenture dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline Corporation’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
4.14	—	Indenture dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
4.15	__	Indenture dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.16	—	Indenture dated as of March 5, 2009, among The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on March 11, 2009 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).

154

Exhibit No.		Description
4.17	—	Eleventh Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.18	—	First Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.19	—	Fifth Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.3 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.20	—	Indenture dated as of February 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.21	—	Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
4.22	—	First Supplemental Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
4.23	—	Indenture dated as of August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 12, 2011 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.24	—	Second Supplemental Indenture,  dated as of November 17, 2011, between Williams Partners  L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed November 18, 2011 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
4.25	—	Indenture, dated as of July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on July 16, 2012 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.26	—	Third Supplemental Indenture (including Form of 3.35% Senior Notes due 2022), dated as of August 14, 2012, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 14, 2012 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
4.27	__	Indenture, dated December 18, 2012 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. as trustee (filed on December 20, 2012 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.28	__	First Supplemental Indenture, dated December 18, 2012, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. as trustee (filed on December 20, 2012 as Exhibit 4.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).

155

Exhibit No.		Description
4.29	__	Fourth Supplemental Indenture, dated as of November 15, 2013, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N .A., as trustee (filed on November 18, 2013 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
4.30	—	Amended and Restated Rights Agreement dated September 21, 2004 by and between The Williams Companies, Inc. and EquiServe Trust Company, N.A., as Rights Agent (filed on September 24, 2004 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.31	—	Amendment No. 1 dated May 18, 2007 to the Amended and Restated Rights Agreement dated September 21, 2004 (filed on May 22, 2007 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.32	—	Amendment No. 2 dated October 12, 2007 to the Amended and Restated Rights Agreement dated September 21, 2004 (filed on October 15, 2007 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.1§	—	The Williams Companies Amended and Restated Retirement Restoration Plan effective January 1, 2008 (filed on February 25, 2009 as Exhibit 10.1 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.2§	—	Form of Director and Officer Indemnification Agreement (filed on September 24, 2008 as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.3§	—	Form of 2013 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 27, 2013 as Exhibit 10.4 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.4§	—	Form of 2013 Restricted Stock Unit Agreement among Williams and certain employees and officers(filed on February 27, 2013 as Exhibit 10.5 to The Williams Companies Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.5§	—	Form of 2013 Nonqualified Stock Option Agreement among Williams and certain employees and officers (filed on February 27, 2013 as Exhibit 10.6 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.6*§	__	Form of 2014 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers.
10.7*§	__	Form of 2014 Restricted Stock Unit Agreement among Williams and certain employees and officers.
10.8*§	__	Form of 2014 Nonqualified Stock Option Agreement among Williams and certain employees and officers.
10.9§	—	Form of 2011 Restricted Stock Unit Agreement among Williams and nonmanagement directors (filed on February 27, 2012 as Exhibit 10.7 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.10§	—	Form of 2012 Restricted Stock Unit Agreement among Williams and nonmanagement directors (filed on August 2, 2012 as Exhibit 10.2 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.11*§	__	Form of 2013 Restricted Stock Unit Agreement among Williams and nonmanagement directors.
10.12§	—	The Williams Companies, Inc. 1996 Stock Plan for Nonemployee Directors (filed on March 27, 1996 as Exhibit B to The Williams Companies, Inc.’s Proxy Statement (File No. 001-04174) and incorporated herein by reference).

156

Exhibit No.		Description
10.13§	—	The Williams Companies, Inc. 2002 Incentive Plan as amended and restated effective as of January 23, 2004 (filed on August 5, 2004 as Exhibit 10.1 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.14§	—	Amendment No. 1 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25, 2009 as Exhibit 10.11 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.15§	—	Amendment No. 2 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25, 2009 as Exhibit 10.12 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.16§	—	The Williams Companies, Inc. 2007 Incentive Plan as amended and restated effective January 19, 2012 (filed on May 1, 2012 as Exhibit 10.12 to The Williams Companies, Inc.’s annual report on Form 10-K/A (File No. 001-04174) and incorporated herein by reference).
10.17§	—	Amended and Restated Change-in-Control Severance Agreement between the Company and certain executive officers (Tier I Executives) (filed on February 27, 2013 as Exhibit 10.14 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.18§	—	Amended and Restated Change-in-Control Severance Agreement between the Company and certain executive officers (Tier II Executives) (filed on February 27, 2012, as Exhibit 10.14 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.19	—	Contribution Agreement, dated as of January 15, 2010, by and among Williams Energy Services, LLC, Williams Gas Pipeline Company, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC and, for a limited purpose, The Williams Companies, Inc, including exhibits thereto (filed on January 19, 2010 as Exhibit 10.1 to The Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.20	—	Separation and Distribution Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (filed on February 27, 2012 as Exhibit 10.19 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.21	—	Employee Matters Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (filed on January 6, 2012 as Exhibit 10.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.22	—	Tax Sharing Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (filed on January 6, 2012 as Exhibit 10.3 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.23	—	Contribution Agreement, dated as of March 19, 2012, between Caiman Energy, LLC and Williams Partners L.P. (filed on April 26, 2012 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599)) and incorporated herein by reference
10.24	—	First Amendment to Contribution Agreement, dated as of April 27, 2012, between Caiman Energy, LLC and Williams Partners L.P. (filed on August 2, 2012 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599) and incorporated herein by reference).
10.25	—	Consulting Agreement and Release dated September 17, 2012, between The Williams Companies, Inc. and Phillip D. Wright (filed on October 31, 2012 as Exhibit 10.2 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.26	—	Contribution Agreement dated as of October 29, 2012, by and among The Williams Companies, Inc., Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC, and Williams Field Services Group, LLC (filed on November 2, 2012 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

157

Exhibit No.		Description
10.27	—	Purchase Agreement dated as of December 11, 2012 with GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P. and GIP-C Holding (CHK), L.P. (filed on February 27, 2013 as Exhibit 10.28 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.28	—	Subscription Agreement dated as of December 11, 2012 by and among Access Midstream Partners, L.P., Access Midstream Partners GP, L.L.C., GIP II Hawk Holdings Partnership, L.P. and The Williams Companies, Inc.(filed on February 27, 2013 as Exhibit 10.29 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.29	__	Form of Commercial Paper Dealer Agreement, dated as of March 12, 2013, between Williams Partners L.P., as Issuer, and the Dealer party thereto (filed on March 18, 2013 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
10.30	__	Amendments Nos. 2, 3, 4, and 5 to Contribution Agreement between Caiman Energy, LLC and Williams Partners L.P. (filed on May 8, 2013 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599) and incorporated herein by reference).
10.31	__	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 Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-32599) and incorporated herein by reference).
10.32	__	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).
12*	—	Computation of Ratio of Earnings to Combined Fixed Charges.
14	—	Code of Ethics for Senior Officers (filed on March 15, 2004 as Exhibit 14 to The Williams Companies, Inc.’s Form 10-K and incorporated herein by reference).
21*	—	Subsidiaries of the registrant.
23.1*	—	Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.
23.2*	—	Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP.
23.3*	—	Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP.
24*	—	Power of Attorney.
31.1*	—	Certification of the 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.
31.2*	—	Certification of the 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.
32**	—	Certification of the Chief Executive Officer and the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	—	XBRL Instance Document.
101.SCH*	—	XBRL Taxonomy Extension Schema.

158

Exhibit No.		Description
101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase.
101.LAB*	—	XBRL Taxonomy Extension Label Linkbase.
101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase.

_________________

*	Filed herewith
**	Furnished herewith
§	Management contract or compensatory plan or arrangement

159

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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)
By:	/s/    TED T. TIMMERMANS
	Ted T. Timmermans Vice President, Controller and Chief Accounting Officer

Date: February 26, 2014

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/    ALAN S. ARMSTRONG	President, Chief Executive Officer and Director	February 26, 2014
Alan S. Armstrong	(Principal Executive Officer)
/s/    DONALD R. CHAPPEL	Senior Vice President and Chief Financial Officer	February 26, 2014
Donald R. Chappel	(Principal Financial Officer)
/s/    TED T. TIMMERMANS	Vice President, Controller and Chief Accounting Officer	February 26, 2014
Ted T. Timmermans	(Principal Accounting Officer)
/s/    JOSEPH R. CLEVELAND*	Director	February 26, 2014
Joseph R. Cleveland*
/s/    KATHLEEN B. COOPER*	Director	February 26, 2014
Kathleen B. Cooper*
/s/    JOHN A. HAGG*	Director	February 26, 2014
John A. Hagg*

/s/    JUANITA H. HINSHAW*	Director	February 26, 2014
Juanita H. Hinshaw*
/s/    RALPH IZZO*	Director	February 26, 2014
Ralph Izzo*
/s/    FRANK T. MACINNIS*	Chairman of the Board	February 26, 2014
Frank T. MacInnis*

/s/    STEVEN W. NANCE*	Director	February 26, 2014
Steven W. Nance*
/s/    MURRAY D. SMITH*	Director	February 26, 2014
Murray D. Smith*

Signature	Title	Date
/S/    JANICE D. STONEY*	Director	February 26, 2014
Janice D. Stoney*
/S/    LAURA A. SUGG*	Director	February 26, 2014
Laura A. Sugg*

*By:	/s/    SARAH C. MILLER	February 26, 2014
	Sarah C. Miller           Attorney-in-Fact

INDEX TO EXHIBITS

Exhibit No.		Description
3.1	—	Amended and Restated Certificate of Incorporation, as supplemented (filed on May 26, 2010 as Exhibit 3.1 to The Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.2	—	By-Laws (filed on May 26, 2010 as Exhibit 3.2 to The Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.1	—	Senior Indenture dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank, Trustee (filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline’s registration statement on Form S-3 (File No. 033-62639) and incorporated herein by reference).
4.2	—	Senior Indenture dated as of July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s registration statement on Form S-3 (File No. 333-02155) and incorporated herein by reference).
4.3	—	Senior Indenture dated February 25, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed February 25, 1997 as Exhibit 4.4.1 to MAPCO Inc.’s Amendment No. 1 to registration statement on Form S-3 (File No. 333-20837) and incorporated herein by reference).
4.4	—	Supplemental Indenture No. 1 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(o) to MAPCO Inc.’s annual report on Form 10-K for the fiscal year ended December 31, 1997 (File No. 001-05254) and incorporated herein by reference).
4.5	—	Supplemental Indenture No. 2 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(p) to MAPCO Inc.’s annual report on Form 10-K for the fiscal year ended December 31, 1997 (File No. 001-05254) and incorporated herein by reference).
4.6	—	Supplemental Indenture No. 3 dated March 31, 1998, among MAPCO Inc., Williams Holdings of Delaware, Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(j) to Williams Holdings of Delaware, Inc.’s annual report on Form 10-K for the fiscal year ended December 31, 1998 (File No. 000-20555) and incorporated herein by reference).
4.7	—	Supplemental Indenture No. 4 dated as of June 30, 1999, among Williams Holdings of Delaware, Inc., Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on March 28, 2000 as Exhibit 4(q) to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
4.8	—	Fifth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed on March 12, 2001 as Exhibit 4(k) to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
4.9	—	Seventh Supplemental Indenture dated March 19, 2002, between The Williams Companies, Inc. as Issuer and Bank One Trust Company, National Association, as Trustee (filed on May 9, 2002 as Exhibit 4.1 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
4.10	—	Indenture dated as of May 28, 2003, by and between The Williams Companies, Inc. and JPMorgan Chase Bank, as Trustee for the issuance of the 5.50% Junior Subordinated Convertible Debentures due 2033 (filed on August 12, 2003 as Exhibit 4.2 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).

Exhibit No.		Description
4.11	—	Indenture dated as of April 11, 2006, between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.12	—	Indenture dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
4.13	—	Indenture dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline Corporation’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
4.14	—	Indenture dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
4.15	__	Indenture dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.16	—	Indenture dated as of March 5, 2009, among The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on March 11, 2009 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.17	—	Eleventh Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.18	—	First Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.19	—	Fifth Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.3 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.20	—	Indenture dated as of February 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.21	—	Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
4.22	—	First Supplemental Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
4.23	—	Indenture dated as of August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 12, 2011 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

Exhibit No.		Description
4.24	—	Second Supplemental Indenture, dated as of November 17, 2011, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed November 18, 2011 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
4.25	—	Indenture, dated as of July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on July 16, 2012 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.26	—	Third Supplemental Indenture (including Form of 3.35% Senior Notes due 2022), dated as of August 14, 2012, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 14, 2012 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
4.27	__	Indenture, dated December 18, 2012 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. as trustee (filed on December 20, 2012 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.28	__	First Supplemental Indenture, dated December 18, 2012, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. as trustee (filed on December 20, 2012 as Exhibit 4.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.29	__	Fourth Supplemental Indenture, dated as of November 15, 2013, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N .A., as trustee (filed on November 18, 2013 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
4.30	—	Amended and Restated Rights Agreement dated September 21, 2004 by and between The Williams Companies, Inc. and EquiServe Trust Company, N.A., as Rights Agent (filed on September 24, 2004 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.31	—	Amendment No. 1 dated May 18, 2007 to the Amended and Restated Rights Agreement dated September 21, 2004 (filed on May 22, 2007 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.32	—	Amendment No. 2 dated October 12, 2007 to the Amended and Restated Rights Agreement dated September 21, 2004 (filed on October 15, 2007 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.1§	—	The Williams Companies Amended and Restated Retirement Restoration Plan effective January 1, 2008 (filed on February 25, 2009 as Exhibit 10.1 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.2§	—	Form of Director and Officer Indemnification Agreement (filed on September 24, 2008 as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.3§	—	Form of 2013 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 27, 2013 as Exhibit 10.4 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.4§	—	Form of 2013 Restricted Stock Unit Agreement among Williams and certain employees and officers(filed on February 27, 2013 as Exhibit 10.5 to The Williams Companies Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.5§	—	Form of 2013 Nonqualified Stock Option Agreement among Williams and certain employees and officers (filed on February 27, 2013 as Exhibit 10.6 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).

Exhibit No.		Description
10.6*§	__	Form of 2014 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers.
10.7*§	__	Form of 2014 Restricted Stock Unit Agreement among Williams and certain employees and officers.
10.8*§	__	Form of 2014 Nonqualified Stock Option Agreement among Williams and certain employees and officers.
10.9§	—	Form of 2011 Restricted Stock Unit Agreement among Williams and nonmanagement directors (filed on February 27, 2012 as Exhibit 10.7 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.10§	—	Form of 2012 Restricted Stock Unit Agreement among Williams and nonmanagement directors (filed on August 2, 2012 as Exhibit 10.2 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.11*§	__	Form of 2013 Restricted Stock Unit Agreement among Williams and nonmanagement directors.
10.12§	—	The Williams Companies, Inc. 1996 Stock Plan for Nonemployee Directors (filed on March 27, 1996 as Exhibit B to The Williams Companies, Inc.’s Proxy Statement (File No. 001-04174) and incorporated herein by reference).
10.13§	—	The Williams Companies, Inc. 2002 Incentive Plan as amended and restated effective as of January 23, 2004 (filed on August 5, 2004 as Exhibit 10.1 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.14§	—	Amendment No. 1 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25, 2009 as Exhibit 10.11 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.15§	—	Amendment No. 2 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25, 2009 as Exhibit 10.12 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.16§	—	The Williams Companies, Inc. 2007 Incentive Plan as amended and restated effective January 19, 2012 (filed on May 1, 2012 as Exhibit 10.12 to The Williams Companies, Inc.’s annual report on Form 10-K/A (File No. 001-04174) and incorporated herein by reference).
10.17§	—	Amended and Restated Change-in-Control Severance Agreement between the Company and certain executive officers (Tier I Executives) (filed on February 27, 2013 as Exhibit 10.14 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.18§	—	Amended and Restated Change-in-Control Severance Agreement between the Company and certain executive officers (Tier II Executives) (filed on February 27, 2012, as Exhibit 10.14 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.19	—	Contribution Agreement, dated as of January 15, 2010, by and among Williams Energy Services, LLC, Williams Gas Pipeline Company, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC and, for a limited purpose, The Williams Companies, Inc, including exhibits thereto (filed on January 19, 2010 as Exhibit 10.1 to The Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.20	—	Separation and Distribution Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (filed on February 27, 2012 as Exhibit 10.19 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).

Exhibit No.		Description
10.21	—	Employee Matters Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (filed on January 6, 2012 as Exhibit 10.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.22	—	Tax Sharing Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (filed on January 6, 2012 as Exhibit 10.3 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.23	—	Contribution Agreement, dated as of March 19, 2012, between Caiman Energy, LLC and Williams Partners L.P. (filed on April 26, 2012 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599)) and incorporated herein by reference
10.24	—	First Amendment to Contribution Agreement, dated as of April 27, 2012, between Caiman Energy, LLC and Williams Partners L.P. (filed on August 2, 2012 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599) and incorporated herein by reference).
10.25	—	Consulting Agreement and Release dated September 17, 2012, between The Williams Companies, Inc. and Phillip D. Wright (filed on October 31, 2012 as Exhibit 10.2 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.26	—	Contribution Agreement dated as of October 29, 2012, by and among The Williams Companies, Inc., Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC, and Williams Field Services Group, LLC (filed on November 2, 2012 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
10.27	—	Purchase Agreement dated as of December 11, 2012 with GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P. and GIP-C Holding (CHK), L.P. (filed on February 27, 2013 as Exhibit 10.28 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.28	—	Subscription Agreement dated as of December 11, 2012 by and among Access Midstream Partners, L.P., Access Midstream Partners GP, L.L.C., GIP II Hawk Holdings Partnership, L.P. and The Williams Companies, Inc.(filed on February 27, 2013 as Exhibit 10.29 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.29	__	Form of Commercial Paper Dealer Agreement, dated as of March 12, 2013, between Williams Partners L.P., as Issuer, and the Dealer party thereto (filed on March 18, 2013 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
10.30	__	Amendments Nos. 2, 3, 4, and 5 to Contribution Agreement between Caiman Energy, LLC and Williams Partners L.P. (filed on May 8, 2013 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-32599) and incorporated herein by reference).
10.31	__	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 Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-32599) and incorporated herein by reference).
10.32	__	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).
12*	—	Computation of Ratio of Earnings to Combined Fixed Charges.

Exhibit No.		Description
14	—	Code of Ethics for Senior Officers (filed on March 15, 2004 as Exhibit 14 to The Williams Companies, Inc.’s Form 10-K and incorporated herein by reference).
21*	—	Subsidiaries of the registrant.
23.1*	—	Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.
23.2*	—	Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP.
23.3*	—	Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP.
24*	—	Power of Attorney.
31.1*	—	Certification of the 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.
31.2*	—	Certification of the 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.
32**	—	Certification of the Chief Executive Officer and the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	—	XBRL Instance Document.
101.SCH*	—	XBRL Taxonomy Extension Schema.
101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase.
101.LAB*	—	XBRL Taxonomy Extension Label Linkbase.
101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase.

_____________

*	Filed herewith
**	Furnished herewith
§	Management contract or compensatory plan or arrangement