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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington,D.C. 20549
Form10-K
(Mark One)



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

For the fiscal year ended December31, 20123

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

dniiainN.


One Williams Center, Tulsa, Oklahoma
74172

(Address of Principal Executive Offices)
(Zip Code)
918-573-2000
(Registrants Telephone Number, Including Area Code)
Securities registered pursuant to Section12(b) of the Act:



Title of Each Class
Name of Each Exchange on Which Registered

Common Stock, $1.00par value
New York Stock Exchange

Preferred Stock Purchase Rights
New York Stock Exchange
Securities registered pursuant to Section12(g) of the Act:
5.50% Junior Subordinated Convertible Debentures due 2033
I ndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule405 of the Securities Act.Yes x No
Indicate by check mark if the registrant is not required to file reports pursuant to Section13 or Section15(d) of the Act.Yes No x
Indicate by check mark whether the registrant: (1)has filed all reports required to be filed by Section13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months (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 90days.Yes x No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yes x No
Indicate by check mark if disclosure of delinquent filers pursuant to Item405 of RegulationS-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in PartIII of this Form10-K or any amendment to this Form10-K.
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 Rule12b-2 of the Exchange Act. (Check one):



Largeacceleratedfiler
x
Acceleratedfiler
Non-accelerated filer
Smallerreportingcompany

(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule12b-2 of the Act).Yes No 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 registrants most recently completed second quarter was approximately $22,144,393,171. The number of shares outstanding of the registrants common stock outstanding at February21, 2014 was 684,417,475 .
DOCUMENTS INCORPORATED BY REFERENCE Portions of the Registrants Definitive Proxy Statement for the Registrants Annual Meeting of Stockholders to be held on May22, 2014, are incorporated into PartIII, as specifically set forth in PartIII.


Non-accelerated filer
(Do not check if a smaller reporting company)
Smallerreportingcompany
Indicate by check mark whether the registrant is a shell company (as defined in Rule12b-2 of the Act).Yes No x
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 registrants most recently completed second quarter was approximately $18,031,364,160.
The number of shares outstanding of the registrants common stock outstanding at February21, 2013 was 681,532,705.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrants Definitive Proxy Statement for the Registrants Annual Meeting of Stockholders to be held on May16, 2013, are incorporated into PartIII, as specifically set forth in PartIII.
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THE WILLIAMS COMPANIES, INC.

OM0K TABLE OF CONTENTS



Page

PARTI


Item1.
Business
34

Website Access to Reports and Other Information
34

General
34

Organizational Restructuring
3

Dividend Growths
4

Financial Information About Segments
54

Business Segments
5

Williams Partners
5

Williams NGL & Petchem Services
162

Access Midstream Partners
173

Additional Business Segment Information
1
84

Regulatory Matters
195

Environmental Matters
2217

Competition
2318

Employees
2419

Financial Information about Geographic Areas
2419

Item1A.
Risk Factors
250

Item1B.
Unresolved Staff Comments
433
Item2.
Properties
434

Item3.
Legal Proceedings
434

Item4.
Mine Safety Disclosures
434
Executive Officers of the Registrant
4435


PARTII


Item5.
Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
439
Item6.
Selected Financial Data
540
Item7.
Managements Discussion and Analysis of Financial Condition and Results of Operations
541
Item7A.
Quantitative and Qualitative Disclosures About Market Risk
875
Item8.
Financial Statements and Supplementary Data
8877

Item9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
15748

Item9A.
Controls and Procedures
15748

Item9B.
Other Information
1571


PARTIII


Item10.
Directors, Executive Officers and Corporate Governance
1581

Item11.
Executive Compensation
1581

Item12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
1581

Item13.
Certain Relationships and Related Transactions, and Director Independence
1592

Item14.
Principal Accountant Fees and Services
1592


PARTIV


Item15.
Exhibits and Financial Statement Schedules
16053
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DEFINITIONS
We use tThe following oil and gas measurements in this report:
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 bcfillion 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 Btus.
ritish 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 Btus.
ritish thermal units MMdth/d : One million dekatherms per day.
TBtu : One trillion Btus.
Other definitions:
FERC : Federal Energy Regulatory Commission.
Fractionation : The process by which a mixed stream of natural gas liquids is separated into its constituent products, such as ethane, pro
ritish thermal units Consolidated Entities : Bluegrass Pipeline: Bluegrass Pipeline Company LLC Constitution: Constitution Pipeline Companey, and butane.
LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures.
NGL : 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.
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.P.,L.C. Access Midstream Ventures, L.L.C.,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, Aux Sable Liquid Products L.P., and Overland Pass Pipeline Company LLC.
Throughput : The volume of product transported or passing through a pipeline, plant,
OPPL: Overland Pass Pipeline Company LLC
2
Government and Regulatory: Code, the: In
terminal, or other facility.
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PARTI

Item1.
Business
In this report, Williams (which includes The Williams Companies, Inc. and, unless the context otherwise requires, 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 Form10-K, quarterly reports on Form10-Q, current reports on Form8-K, proxy statements and other documents electronically with the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended (Exchange Act). You may read and copy any materials that we file with the SEC at the SECs Public Reference Room at 100FStreet, 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 SECs Internet website at www.sec.gov.
Our Internet website is www.williams.com . We make available f
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: WPZs April 2012 purchase of 100 percent of Caiman Eastern Midstream, LLC located in the Ohio River Valley areea of charge through the Investor tab of our Internet website our annual report on Form10-K, quarterly reports on Form10-Q, current reports on Form8-K and amendments to those reports filed or furnished pursuant to Section13(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 upthe 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 written request to our Corporate Secretary, One Williams Center, Suite4700, Tulsa, Oklahoma74172.
GENERAL
We are primarily an energy infrastructure company focused on connecting North Americas 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 pipeline, 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.We own the general partner interest and a 68 percent limited-partner interest in WPZ.We also own a Canadian midstream business, which processes oil sands 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.
ORGANIZATIONAL RESTRUCTURING
Following the spin-off of WPX Energy, Inc. (WPX) at the end of 2011 and in consideration of our growth plans, we initiated an organizational restructuring evaluation to better align resources to support an ongoing business strategy 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. As a result of this
ght Laser Acquisition: WPZs 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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evaluation, certain organizational changes were implemented January1, 2013, that gener
PART I Item1. Business In this report, Williams (which includes The Williams Companies, Inc. and, unless the context otherwise indicates, ally organize our businesses in geographically based operating areas and centralize certain operational support functions. This will have no impact on our segment presentation, including Williams Partners as it continues to be 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 (See Note 18 of Notes to Consolidated Financial Statements).
Information in this report has generally been prepared to be consistent with the reportable segment presentation in our consolidated financial statements in Part II, Item8 of this document. Our reportable segment presentation will not change as a result of the restructuring. These segments are discussed in further detail in the following sections.
DIVIDEND GROWTH
We increased our quarterly dividends from $0.25 per share in the fourth qu
f 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 Form10-K, quarterly reports on Form10-Q, current reports on Form8-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 SECs Public Reference Room at 100FStreet, 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 SECs 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 Form10-K, quarterly reports on Form10-Q, current reports on Form8-K and amendments to those reports filed or furnished pursuant to Section13(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, Suite4700, Tulsa, Oklahoma74172. GENERAL We are primarily an energy infrastructure company focused on connecting North Americas 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 partner of 2011 to $0.325 per share in the fourth quships.As of December 31, 2013, we own the general partner interest and a 62 percent limited-partner of 2012. Also, consistent with our expectation of receiving increasing cash distributions from our interest in WPZ and Access Midstream Partners, we expect tointerest 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 dividend on a quarterly basisquarterly 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 $0.3387540250 per share for the first quarter of 2013 and we expect total 2013 divid4. FINANCIAL INFORMATION ABOUT SEGMENTS See Item8 Financial Statements and Supplementary Data Notes to Consolidated Financial Statemendts to be $1.44 per share, which is approximately 20 percent higher than 2012. We expect 2014 divideNote 18 Segment Disclosures for information with respect to each segments revenues, profits or losses ands to be $1.75tal assets.4
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FINANCIAL INFORMATION ABOUT SEGMENTS
See Item8 Financial Statements and Supplementary Data Notes to Consolidated Financial Statements Note18 for inf
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 transp
ormtation with respect to each segments revenues, profits or losses and total assets.
BUSINESS SEGMENTS
Substantially all our operations are conducted through our subsidiaries. Our activities in 2012 were primarily operated through the following business segments:
; 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.


WilliAccess Midstreams 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 venture investments, and the midstream businessan 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 ngatural gas gatherhering, processing, treating and comprocessiong services; NGL production, fractionation, storage, marketing and trans to Chesapeake Energy Corportation; 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 venture invest 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.)

Williams NGL& Petchem Services ( formerly referred to as Midstream Canada& Olefins) primarily comprised of our Canadian midstream operations and certain of our recently acquired domestic olefins pipeline assets. Our Canadian operations include an oil sands offgas processing plant located near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and butylenes/butane splitter (B/B splitter) facility, both of which are located at Redwater, Alberta, which is near Edmonton, Alberta.

Access Midstream Partners comprised of an indirect equity interest in Access Midstream Partners GP, L.L.C. (Access GP) and limited partner interests in Access Midstream Partners, L.P. (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 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. Managements 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 December31, 2013, Transcos 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
5
total of approximately 10.2 MMdth of natural gas per day. Transcos system includes 45 compressor stations, four underground storage fields, and an LNG storage facility. Compression facilities at sea level-rated capacity total approximately 1.7million horsepower. Transcos major natural gas transportation customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on Transcos system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Transcos firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Transcos 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 December31, 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 Transcos 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 December31, 2013, Northwest Pipelines 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 Pipelines firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of Northwest Pipelines 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.
6
Midstream Business Williams Partners midstream business, one of the nations 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:


Other primarily comprised of corporate operations.
This report is organized to reflect this structure. Detailed discussion of each of our business segments follows.
Williams Partners
Gas Pipeline Business
Williams Partners owns and operates a combined total of approximately 13,700 miles of pipelines with a total annual throughput of approximately 3,400 TBtu of natural gas and peak-day delivery capacity of approximately 14 MMdth of natural gas. Our gas pipeline businesses consist primarily of Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline GP (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 Natural Gas System, LLC (Gulfstream) and a 51 percent interest in Constitution Pipeline Company, LLC (Constitution).
Transco
Transco is an interstate natural gas transmission company that owns and operates a 9,800-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., New York, New Jersey and Pennsylvania.
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Pipeline system and customers
At December31, 2012, Transcos system had a mainline delivery capacity of approximately 5.8 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 4.0 MMdth of natural gas per day for a system-wide delivery capacity total of approximately 9.8 MMdth of natural gas per day. Transcos system includes 45 compressor stations, four underground storage fields, and an LNG storage facility. Compression facilities at sea level-rated capacity total approximately 1.5million horsepower.
Transcos major natural gas transportation customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on Transcos system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Transcos firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Transcos business. Additionally, Transco offers storage services and interruptible transportation services under short-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 December31, 2012, our customers had stored in our facilities approximately 150 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 Transcos customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.
Transco expansion projects
The pipeline projects listed below were completed during 2012 or are future significant pipeline projects for which Transco has customer commitments.
Mid-South
The Mid-South Expansion Project involves an expansion of Transcos mainline from Station 85 in Choctaw County, Alabama, to markets as far downstream as North Carolina. The capital cost of the project is estimated to be approximately $200 million. Transco placed the first phase of the project into service in September 2012, which increased capacity by 95 Mdth/d. Transco plans to place the second phase into service in June 2013, which is expected to increase capacity by an additional 130 Mdth/d.
Mid-Atlantic Connector
The Mid-Atlantic Connector Project involves an expansion of Transcos mainline from an existing interconnection in North Carolina to markets as far downstream as Maryland. The capital cost of the project was approximately $60 million. The project was placed into service in the first quarter of 2013, increasing capacity by 142 Mdth/d.
Northeast Supply Link
In November 2012, Transco received approval from the FERC to expand its 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 capital cost of the project is estimated to be approximately $390 million. Transco plans to place the project into service in November 2013, and it is expected to increase capacity by 250 Mdth/d.
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Rockaway Delivery Lateral
In January 2013, Transco filed an application with the FERC for the construction of a three-mile offshore lateral to a distribution system in New York. The capital cost of the project is estimated to be approximately $180 million. Transco plans to place the project into service during the second half of 2014, with an expected capacity of 647 Mdth/d.
Virginia Southside
In December 2012, Transco filed an application with the FERC to expand Transcos existing natural gas transmission system from the Zone 6 Station 210 Pooling Point in New Jersey to Dominion Virginia Powers proposed power station in Brunswick County, Virginia, and our Cascade Creek interconnect with East Tennessee Natural Gas and our Pleasant Hill delivery point to Piedmont Natural Gas Company, Inc. in North Carolina.The capital cost of the project is estimated to be approximately $300 million. Transco plans to place the project into service in September 2015, and is expected to increase capacity by 270 Mdth/d.
Leidy Southeast
The Leidy Southeast Project involves an expansion of Transcos existing natural gas transmission system from the Marcellus Shale production region in Pennsylvania to a pooling point in Alabama. Transco anticipates filing an application with the FERC in the fourth quarter of 2013. The capital cost of the project is estimated to be approximately $600 million. Transco plans to place the project into service in December 2015, and it is expected to increase capacity by 469 Mdth/d.
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 December31, 2012, Northwest Pipelines system, having long-term firm transportation agreements including peaking service 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 Pipelines firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of Northwest Pipelines 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.
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Northwest Pipeline expansion project
North and South Seattle Lateral Delivery Expansions
Northwest Pipeline has executed agreements with a customer to expand the North and South Seattle laterals and provide additional lateral capacity of approximately 80 Mdth/d and 74 Mdth/d, respectively. The total estimated cost of the project is between $32 and $36 million. We placed North Seattle into service in November 2012. South Seattle is currently targeted for service in fall 2013.
Gulfstream
Gulfstream is a 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, and Spectra Energy Partners, LP, own the other 50 percent interest. Williams Partners shares operating responsibilities for Gulfstream with Spectra Energy Corporation and accounts for this using the equity method as described in Note 1 of our Notes to Consolidated Financial Statements.
Constitution Pipeline
In April 2012, Williams Partners began the FERC pre-filing process for a new interstate gas pipeline project. We currently own 51 percent of Constitution Pipeline with two other parties holding 25 percent and 24 percent, respectively. Williams Partners will be the operator of Constitution Pipeline. The new 120-mile Constitution Pipeline will connect Williams Partners gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. The total cost of the entire project is estimated to be $680 million. Williams Partners plans to place the project into service in March 2015, with an expected capacity of 650thousand dekatherms per day (Mdth/d). The pipeline is fully subscribed with two shippers. Williams Partners expects to file a FERC application during the second quarter of 2013.
Midstream Business
Williams Partners midstream business, one of the nations 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.
Expansion Projects
The midstream projects listed below were completed during 2012 or are future significant projects.
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Northeast
Ohio Valley
In April 2012, WPZ completed the acquisition of 100 percent of the ownership interest in Caiman Eastern Midstream, LLC (Caiman Acquisition). The acquisition provides us with a significant footprint and growth potential in the natural gas liquids-rich Ohio River Valley area of the Marcellus Shale. Several projects were completed in the fourth quarter of 2012 increasing our gathering, processing and fractionating capacities. The Fort Beeler plant complex has 320 MMcf/d of cryogenic processing capacity currently available. The Moundsville fractionator is now in service with approximately 13 Mbbls/d of NGL handling capacity. An NGL pipeline, connecting the Fort Beeler plant to the Moundsville fractionator has also been completed and is in service.
We also have expansions currently under construction 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 is expected to add 200 MMcf/d of processing capacity in the first quarter of 2013. By the end of 2013, we expect our first turbo-expander at our Oak Grove facility to add 200 MMcf/d of processing capacity and additional fractionation capacity at our Moundsville fractionators bringing the NGL handling capacity to approximately 43 Mbbls/d.
Caiman II
In July 2012, WPZ formed Caiman Energy II, LLC with Caiman Energy, LLC and others to develop large-scale natural gas gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and northwest Pennsylvania.As a result, through our 47.5 percent ownership, WPZ plans to contribute $380 million through 2014 to fund a portion of Blue Racer Midstream, a joint project formed in December 2012 between Caiman Energy II, LLC and another party.
Susquehanna Supply Hub
In February 2012, WPZ completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC (Laser Acquisition). The gathering system is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in Susquehanna County, in northeastern Pennsylvania, as well as 10 miles of gathering pipeline in southern New York. The acquisition is supported by existing long-term gathering agreements that provide acreage dedications and volume commitments.
Our Springville pipeline, a 33-mile, 24-inch diameter natural gas gathering pipeline, connecting a portion of our gathering assets into the Transco pipeline, was placed into service in January 2012, and expansions were completed in the third quarter of 2012 allowing us to deliver approximately 625 MMcf/d into the Transco pipeline. This new take-away capacity allows full use of approximately 1.6 Bcf/d of capacity from various compression and dehydration expansion projects to our gathering business in northeastern Pennsylvanias Marcellus Shale which we acquired at the end of 2010.
As production in the Marcellus increases and expansion projects are completed, the Susquehanna Supply Hub is expected to reach a natural gas take away capacity of 3 Bcf/d by 2015, including capacity contributions from the Constitution Pipeline.
Laurel Mountain Midstream
In addition, we plan expansions to our gathering system infrastructure through capital to be invested within our Laurel Mountain equity investment, also in the Marcellus Shale region.
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Atlantic-Gulf
Gulfstar FPS Deepwater Project
We will design, construct, and install our Gulfstar FPS, a spar-based floating production system that utilizes a standard design approach with a capacity of 60 Mbbls/d of oil, up to 200 MMcf/d of natural gas, and the capability to provide seawater injection services. We expect Gulfstar FPS to be capable of serving as a central host facility for other deepwater prospects in the area. Construction is underway and the project is expected to be in service in 2014. In January 2013, WPZ agreed to sell a 49 percent ownership interest in its Gulfstar FPS project to a third party. The transaction is expected to close in second-quarter 2013, at which time we expect the third party will contribute $225 million to fund its proportionate share of the project costs, following with monthly capital contributions to fund its share of ongoing construction.
Keathley Canyon Connector
Our equity investee which we operate, Discovery Producer Services LLC (Discovery), plans to construct, own, and operate a new 215-mile, 20-inch deepwater lateral pipeline from a third-party floating production facility located in the Keathley Canyon production area in the central deepwater Gulf of Mexico. Discovery has signed long-term agreements with anchor customers for natural gas gathering and processing services for production from the Keathley Canyon and Green Canyon areas. The Keathley Canyon Connector lateral will originate from a third-party floating production facility in the southeast portion of the Keathley Canyon area and will connect to Discoverys existing 30-inch offshore natural gas transmission system. The lateral pipeline is estimated to have the capacity to flow more than 400 MMcf/d and will accommodate the tie-in of other deepwater prospects. Pre-construction activities have begun; the pipeline is expected to be laid in 2013 and in service in mid-2014.
West
Parachute
In conjunction with a basin-wide agreement for all gathering and processing services provided by us to WPX in the Piceance basin, we plan to construct a 350 MMcf/d cryogenic natural gas processing plant. The Parachute TXP I plant is expected to be in service in 2014.
NGL& Petchem Services
Overland Pass Pipeline
Through our equity investment in Overland Pass Pipeline Company LLC, we are participating in the construction of a pipeline connection and capacity expansions, expected to be complete in early 2013, to increase the pipelines capacity to the maximum of 255 Mbbls/d, to accommodate new volumes coming from the Bakken Shale in the Williston basin.
Geismar
With the benefit of a $350-$400 million expansion under way and scheduled for completion by late 2013, the facilitys annual ethylene production capacity will grow by 600million pounds to 1.95 billion pounds. Along with ethane, propane and ethylene, the Geismar facility also produces propylene, butadiene, and debutanized aromatic concentrate (DAC). The additional capacity will be wholly owned by us and is expected to increase our share of the Geismar production facility to over 88 percent.
In the fourth quarter of 2012, we also completed the construction of a pipeline which is capable of supplying 12 Mbbls/d of ethane to our Geismar olefins production facility from Discoverys Paradis fractionator.
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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:

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:

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
will includes a share of the margins on the NGLs produced. For the year ended December31, 20123, 6372 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 December31, 2013, 26 percent of the NGL production volumes were under keep-whole contracts.


Keep-whole: Under keep-wholePercent-of-Liquids: Under percent-of-liquids processing 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 connection with this type of processing agreement are referred to as our equity NGL production. Under these agreements, we have commoditydeliver 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 December31, 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 prioce exposure on the difference between NGL and natural gas prices. For the year ended December31, 2012, 34 percent of the NGL production volumes were under keep-whole contracts.ss or condition natural gas supplies delivered to the Transco pipeline. Our SanJuan basin, southwest Wyoming, and Piceance systems are capable of delivering residue gas volumes into Northwest Pipelines interstate system in addition to third-party interstate systems. Our gathering system in Pennsylvania delivers residue gas volumes into Transcos 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 December31, 2013:


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 December31, 2012, 3 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 new 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
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surrounding its infrastructure. During 2012, Williams Partners facilities gathered and processed gas for approximately 220 customers. Williams Partners top six gathering and processing customers accounted for approximately 54 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 SanJuan basin, southwest Wyoming and Piceance systems are capable of delivering residue gas volumes into Northwest Pipelines interstate system in addition to third-party interstate systems. Our gathering system in Pennsylvania delivers residue gas volumes into Transcos 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, and West Virginia. 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.
The following table summarizes our significant operated natural gas gathering assets as of December31, 2012:


Natural Gas Gathering Assets

Location
Pipeline
Miles
Inlet

Capacity
(Bcf/d)
Ownership

neet Supply Basins

West

Rocky Mountain
Wyoming
3,587
1.1
100
% Wamsutter&SWWyoming

Four Corners
Colorado & New Mexico
3,82341
1.8
100
% San Juan

Piceance
Colorado
328
1.4
(2)
Piceance

Northeast

Ohio Valley
West Virginia
10174
0.8
100
% Appalachian

Pennsylvania &
New York
Susquehanna Supply Hub
Pennsylvania & New York
191
1.7
277
2.3

100

% Appalachian

Laurel Mountain (1)
Pennsylvania
2,01344
0.
67
51

% Appalachian

Atlantic-Gulf

Canyon Chief & Blind Faith
Deepwater Gulf of Mxc
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
2
45
0.9
08
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
pPiceance gathering system.
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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 to produce approximatelyhat 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 December31, 2012:3:



NtrlGsPoesn aiiis
Location
Inlet
Capacity
(Bcf/d)
NGL

Production
Capacity
(Mbbls/d)
Ownership

neet Supply Basins

West

Opal
Opal, WY
1.5
70
100
% SWWyoming

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
RioBlancoCounty,CO
0.5
30
100
% Piceance

Parachute
Garfield County, CO
1.43
7
(2)100%
Piceance

Northeast

Fort Beeler
Marshall County, WV
0.35
3762
100

% Appalachian

Atlantic-Gulf

Markham
Markham, TX
0.5
45
100
% WesternGulfofMexico

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
s that we operate,; however, our financial statements report equity method income from these investments based on our equity ownership percentage.is 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 December31, 2013:

(2)
We own 60 percent of the Sagebrush plant, which we operate, with an inlet capacity of 35 MMcf/d and NGL handling capacity of less than 1 Mbbls/d. We own and operate 100 percent of the balance of the parachute plant complex.
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 table summarizes our significant crude oil transportation pipelines as of December31, 2012:


CueOlPplns
Pipeline
Miles
Capacity

(Mbbls/d)
Ownership

neet SupplyBasins

Mountaineer & Blind Faith
155
150
100
% EasternGulfofMexico

BANJO
57
90
100
% WesternGulfofMexico

Alpine
96
85
100
% Western Gulf of Mexico

Perdido Norte
74
150
100
% Western Gulf of Mexico
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The following table summarizes our production handling platforms as of December31, 2012:



Production Handling Platforms

GasInlet
Capacity
(MMcf/d)
Crude/NGL

Handling
Capacity
(Mbbls/d)
Ownership

neet SupplyBasins

Devils Tower
210
60
100
% EasternGulfofMexico

Canyon Station
500
16
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
s that we operate,; however, our financial statements report equity method income from theseis investments based on our equity ownership percentage.
Gulf Olefins

In November 2012, we contributed to
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 1.35billion pounds of ethylene and 90million 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. In the fourth quarter of 2012, we placed a pipeline in servicWe also own a pipeline that has the capacity to supply 12 Mbbls/d of ethane from Discoverys Paradis fractionator to the Geismar plant.
On June13, 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 facilitys 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 Managements 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 500million 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 Overland Pass PipelinePPL 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 149percent, 174 percent, and 157 percent of our consolidated revenues in 20123, 20112, and 20101, 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.
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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 31.45 percent interest in another fractionation facility in Baton Rouge, Louisiana, with a capacity of 60Mbbls/d. We also own approximately 20million barrels of NGL storage capacity in central Kansas near Conway.
We own approximately 1780 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 Liquid Products L.P. (Aux Sable) and its Channahon, Illinois, gas processing and NGL fractionation facility near Chicago. The facility is capable of processing up to 2.1Bcf/d of natural gas from the Alliance Pipeline system and fractionating approximately 102Mbbls/d of extracted liquids into NGL products. Additionally, in June 2011, Aux Sable acquiredowns 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. Discoverys assets include a 600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 32Mbbls/d NGL fractionator plant near Paradis, Louisiana, and an offshore natural gas gathering and transportation system in the Gulf of Mexico.
Laurel Mountain
We own a 51 percent interest in a joint venture, Laurel Mountain Midstream, LLC (Laurel Mountain), in the Marcellus Shale located in western Pennsylvania. Laurel Mountains assets, which we operate,
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 of approximately 2,000 miles of pipelthat we operate ine with a capacity of approximately 630 MMcf/destern Pennsylvania. Laurel Mountain has a long-term, dedicated, volumetric-based fee agreement, with some exposure to natural gas prices, to gather the anchor customers production in the western Pennsylvania area of the Marcellus Shale. Construction is ongoing for numerous new pipeline segments and compressor stations, the largest of which is our Shamrock compressor station.
Overland Pass Pipeline
We also operate and own a 50 percent ownership interest in Overland Pass Pipeline Company LLC (OPPL). OPPL includes a 760-milePPL . OPPL is capable of transporting 255Mbbls/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 150- and 125-mile extensions into the Piceance and Denver-Julesberg basins in Colorado, respectively. 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. We are constructing a pipeline connection and capacity expansions expected to be complete in early 2013, to increase the pipelines capacity to the maximum of 255 Mbbls/d, to accommodate new volumes coming from the Bakken Shale in the Williston basin.
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Operating Statistics
The following table summarizes our significant operating statistics for Williams Partners midstream business:



2013
2012
2011
2010

Volumes: (1)

Gathering (Tbtu)
1,731
1,616
1,377
1,262

Plant inlet natural gas (Tbtu)
1,549
1,638
1,592
1,599

NGL production (Mbbls/d) (2)
143
2069
189
178

NGL equity sales (Mbbls/d) (2)
40
77
77
80

Crude oil transportation (Mbbls/d) (2)
117
126
105
94

Geismar ethylene sales (millions of pounds)
467
1,058
1,038
981__________


(1)
Excludes volumes associated with
pPartially oOwned assets such as our Discovery and Laurel Mountain investments that are not consolidated for financial reporting purposes.Entities.


(2)
Annual average Mbbls/d.

Williams NGL& Petchem Services
The Williams NGL& Petchem Services segment, formerly referred to as Midstream Canada & Olefins, consists primarily of our Canadian midstream business and certain domestic olefins pipeline assets. 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.
12

Our Canadian operations
that include an oil sands offgas processing plant located near FortMcMurray, Alberta, and an NGL/olefin fractionation facility and butylene/butane splitter (B/B sSplitter) 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. The B/B splitter was completed and placed into service in August 2010. 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 treater/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 121MMcf/d with the ability to recover in excess of
1726Mbbls/d of olefin and NGL products. Our Redwater fractionator has a liquids handling capacity of 1826 Mbbls/d. The B/B sSplitter, 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 was completed and placed into service in June 2012. 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.
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Expansion Projects
Construction began in the fourth quarter of 2011 on the ethane recovery project that will allow us to produce ethane/ethylene mix from our operations that process offgas from the Alberta oil sands. We are modifying our oil sands offgas extraction plant near Fort McMurray, Alberta, and constructing a de-ethanizer at our Redwater fractionation facility. Our de-ethanizer, which will have a production capacity of 17,000 bbls/d, will enable us to initially produce approximately 10,000 bbls/d of ethane/ethylene mix. We have signed a long-term contract to provide the ethane/ethylene mix to a third-party customer. We expect the project to be constructed using cash previously generated from Canadian and other international projects and we expect to complete the expansions and begin producing ethane/ethylene mix in mid-year 2013.
During the third quarter of 2012, we signed a long-term agreement to provide gas processing to a second bitumen upgrader in Canadas oils sands near Fort McMurray, Alberta. To support the new agreement, we plan to build a new liquids extraction plant, supporting facilities and an extension of the Boreal Pipeline to enable transportation of the NGL/olefins mixture to our Redwater facility. The NGL/olefins recovered are initially expected to be approximately 12,000 bbls/d by mid-2015, growing to approximately 15,000 bbls/d by 2018. 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. We expect to fund construction using cash from Canadian opera
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 international cash on-hand.
During the fourth quarter of 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
execution of formal customer commitments. We currently estimate the Bluegrass Pipeline will be in-service in mid-to-late 2014.
6. Operating sStatistics
The following table summarizes our significant operating statistics:



2013
2012
2011
2010

Volumes:

Canadian propylene sales (millions of pounds)
118
153
139
127

Canadian NGL sales (millions of gallons)
172
165
163
145
Access Midstream Partners
Our Access Midstream Partners segment consists of our recentequity investment in Access GP and ACMP. We now 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 rightCMP. This investment includes an indirect 50 percent interest in Access GP, including IDRs. In addition, we hold approximately 243 percent of ACMPs outstanding limited partnership units, for a combined ownership interest of approx. ACMP is a publicly traded master limaitely 25 percent of ACMP. Access Midstream Partnersd partnership that provides gathering, treating, and compression services to Chesapeake Energy Corporation and other leading producers under long-term, fee-based contracts. For the year ended December31, 2012, ACMPs assets gathered approximately 2.8 Bcf of natural gas per day. ACMPs primary gathering systems consist of the following:
Barnett Shale
These assets consist of 25 interconnected gathering systems and 850 miles
producers under long-term, fee-based contracts.
13
The following table summarizes ACMPs 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 pPipeline. Average throughput for the year ended December31, 2012, w (Miles)
Gas Compression (Horsepower)

Region

Barnett Shale
Tex
as
1.195 Bcf/d.
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045
859
150,945

Eagle Ford Shale
T
hese assets consist of 10 gathering systems and 624 miles of pipeline. Gross throughput for the year ended December31, 2012, was just under 0.2 Bcf/d.exas
0.263
870
93,847

Haynesville Shale
The Springridge gathering system consists of 263 miles of pipeline. Average throughput for the year ended December31, 2012, was 0.36 Bcf/d.
The Mansfield gathering system consists of 307 miles of pipeline. Average throughput for the year ended December31, 2012, was 0.72 Bcf/d.
Louisiana
0.669
582
20,195

Marcellus Shale
ACMP operates and owns a 47 percent interest in a gathering system consisting of 10 gathering systems and 549 miles of pipeline. Average net throughput for the year ended December31, 2012, was 0.7 Bcf/d. In addition to the partially owned systems, during December 2012, 622 miles of pipeline was acquired with an average throughput of 0.026 Bcf/d.Pennsylvania & West Virginia
1.019
823
136,090

Niobrara Shale
This gathering system consists of two interconnected gathering systems and 105 miles of pipeline. Average throughput for the year ended December31, 2012, was 0.013 Bcf/d.Wyoming
0.015
132
15,665

Utica Shale
TOhis gathering system consists of 371 miles of pipeline.o
0.107
265
63,505

Mid-Continent
T
his gathering system consists of 2,584 miles of pipeline. Average throughput for the year ended December31, 2012, was 0.56 Bcf/d.
exas, 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 ACMPs Partnership interest.
Additional Business Segment Information
Our ongoing business segments are accounted for as continuing operations in the accompanying financial statements and Notes to Consolidated Financial Statements included in PartII.
Operations related to certain assets in Discontinued Operations have been reclassified to Discontinued O
presented as continuing operations in the accompanying financial statements and Notes to Consolidated Financial Statements included in PartII.
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.
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Revenues by service that exceeded 10 percent of consolidated revenue include:



2013
2012
2011
2010

(Millions)

Service:
(Millions)

Regulated natural gas transportation and storage
$
1,713
$
1,609
$
1,569
1,506

Gathering & processing
1,100
948
840
932
844
703
14

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 FERCs 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 pipeline and midstream 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
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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 U.S.nited 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.
15
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. Our pipelines are designed, operated, and maintained to keep the facilities in compliance with state pipeline safety requirements.
O
n 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
Transco and Northwest Pipeline have developed an
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 Iintegrity Mmanagement Pprogram includes a baseline assessment plan along with periodic reassessments to be completed within required time frames. In meeting the integrity regulations, Transco and Northwest Pipeline have identified high consequence areas and developed baseline assessment plans. Transco and Northwest Pipeline completed assessmentwe 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 Pipelines and Transcos 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 frame, with one exception which was reported to PHMSAs. 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 20123 assessments will be approximately $20 million100,000, most of which we expect to be 2013 capitalincluded in 2014 operating expenditurses. Ongoing periodic reassessments and initial assessments of any new high consequence areas willare 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 and, therefore, recoverable through Transcos and Northwest Pipelines rates.
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. 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.
16
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.
Domestic
Olefins
Williams Partners domestic 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 Resources Conservation Boardgulator (AERCB) and Alberta Environment), 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 AERCB and Alberta Environment have implemented 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.
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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;

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 We are subject to risks associated with climate change and the regulation of greenhouse gas emissions, Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs, liabilities and expenditures and could exceed current expectations, and Increased regulation of energy extraction activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, which could decrease the volume of natural gas and other products that we transport, gather, process and treat and Managements Discussion and Analysis of Financial Condition and Results of Operations Environmental and Environmental Matters in Note17 of our Notes to Consolidated Financial Statements.
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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 attach 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 customers 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. Accordingly, we believe that we are often not considered by such companies to be a direct competitor. 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 treater/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, demand for those supplies in our traditional markets, and the prices of natural gas , 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 additional customer contracts or contracted volumes on favorable terms, if at all, which could affect our financial condition, the amount of cash available to pay dividends, and our ability to grow.
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EMPLOYEES
At February1, 2013, we had approximately 4,639 full-time employees.
FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS
See Note18 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 Note18 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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Item1A.
Risk Factors
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,
17
and Managements 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 customers 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
18
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 February1, 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.
19
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 Section27A of the Securities Act of 1933, as amended, and Section21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements relate to anticipated financial performance, managements 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 managements beliefs and assumptions and on information currently available to management and include, among others, statements regarding:


Amounts and nature of future capital expenditures;


Expansion and growth of our business and operations;


Financial condition and liquidity;


Business strategy;


Cash flow from operations or results of operations;


The levels of dividends to stockholders;

Seasonality of certain business components; and

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, volatility of prices, and the availability and cost of capital;

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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The strength and financial resources of our competitorAbility to acquire new businesses and assets and successfully integrate those operations and assets into our existing businesses, as well as successfully expand our facilities

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

Development of alternative energy sources;

The impact of operational and development hazards;
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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 maintenance and construction costs;


Changes in the current geopolitical situation;

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

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


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


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

Risks associated with future weather conditions;

Acts of terrorism, including cybersecurity threats and related disruptions; andRisks 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:


Additional risks described in our filings with the Securities and Exchange Commission.
Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section.
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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 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. Any of the foregoing 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 relatively minor changes in the supply of and demand for these commodities, market uncertainty and other factors that are beyond our control, including:
Worldwide and domestic supplies of and demand for natural gas, NGLs, olefins, oil, and related commodities;

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

Turmoil in the Middle East and other producing regions;


The activities of the Organization of Petroleum Exporting Countries;

Terrorist attacks on production or transportation assets;

Weather conditionsThe level of consumer demand;
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;

Volatility in the natural gas and oil markets;

The
overall economic environmentcredit 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
;
The credit of participants in the markets where products are bought and sold; and

The adoption of regulations or legislation relating to climate change and changes in natural gas production from exploration and production areas that we serve.
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, demand for those supplies in our traditional markets, and the prices of natural gas.
The development of the additional natural gas reserves that are essential for our natural gas transportation and midstream businesses to thrive requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to our pipeline systems. Low prices for natural gas, regulatory
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limitations, including environmental regulations, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transportation and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our gathering, transportation and processing facilities.
Production from existing wells and natural gas supply basins with access to our pipeline and gathering systems will also naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported on or gathered through our pipeline systems and cash flows associated with the gathering and transportation of natural gas, our customers must compete with others to obtain adequate supplies of natural gas. In addition, if natural gas prices in the supply basins connected to our pipeline systems are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities. If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply areas, if natural gas supplies are diverted to serve other markets in which we have a limited or no presence, if development in new supply basins where we do not have significant gathering or pipeline systems reduces demand for our services, or if environmental regulators restrict new natural gas drilling, the overall volume of natural gas transported, gathered and stored on our systems would decline, which could have a material adverse effect on our business, financial condition and results of operations. In addition, new LNG import facilities built near our markets could result in less demand for our gathering and transportation facilities.
We may not be able to grow or effectively manage our growth.
A principal focus of our strategy is to capitalize on growth opportunities. Our future growth will depend upon our ability to successfully identify, finance, acquire, integrate and operate projects and businesses. Failure to achieve any of these factors would adversely affect our ability to achieve growth.
We have recently completed, or are in the process of completing, significant growth acquisitions and construction projects and may engage in similar growth activities in the future to capture anticipated future demand for natural gas, NGL and olefins infrastructure. This demand may not ultimately materialize. As a result, our new or expanded facilities or businesses may not achieve profitability. In addition, the process of integrating newly acquired or constructed assets into our operations may result in unforeseen operating difficulties, may absorb significant management attention and may require financial resources that would otherwise be available for the ongoing development and expansion of our existing operations. Acquisitions or construction projects may require substantial new capital and could result in the incurrence of indebtedness, additional liabilities and excessive costs that could have a material adverse effect on our business, results of operations, financial condition and our ability to pay dividends to our stockholders. If we issue additional equity in connection with future growth activities, stockholders ownership interest in us may be diluted and dividends we pay to our stockholders may be reduced. Further, any limitations on our access to capital, including limitations caused by illiquidity in the capital markets, may impair our ability to complete future acquisitions and construction projects on favorable terms, if at all.
Our acquisition attempts may not be successful or may result in completed acquisitions that do not perform as anticipated.
We have made and may continue to make acquisitions of businesses and properties. However, suitable acquisition candidates may not continue to be available on terms and conditions we find acceptable. The following are some of the risks associated with acquisitions, including any completed or future acquisitions:
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;

Some of the acquired businesses or properties may not produce revenues, earnings or cash flow at anticipated levels or could have environmental, permitting or other problems for which contractual protections prove inadequate;
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We may lose all or part of the value of our investment or be required to contribute additional capital to support businesses or properties acquiredAcquisitions 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;
We may assume liabilities that were not disclosed to us or that exceed our estimates;

We may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and oAcquisitions 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 benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; andavailable 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 December31, 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 Entitys 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:


Acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures.
Execution of our capital projects subjects us to construction risks, increases in labor costs and materials, and other risks that may adversely affect financial results.
Our growth may be dependent upon the construction of new natural gas gathering, transportation, compression, processing or treating pipelines and facilities, NGL fractionation or storage facilities or olefins processing facilities, as well as the expansion of existing facilities. Construction or expansion of these facilities is subject to various regulatory, development and operational risks, including:

The ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable termmount of cash that WPZ, our other subsidiaries and the Partially Owned Entities distribute to us

The availability of skilled labor, equipment, and materials to complete expansion projects;

Potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceedingThe amount of cash we generate from our operations, our working capital needs, our level of capital expenditures, and our increase the anticipated cost of the project;ability to borrow;
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Impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms;

The ability to conrestruict projects within estimated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials, laborions contained in our indentures and credit facility and our other factors beyond our control, that may be material; anddebt service requirements;

The ability to access capital markets to fund construction projects.
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. As a result, new facilities may not achieve expected investment return, which could adversely affect our results of operations, 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 December31, 2012, our investments in the Partially Owned Entities accounted for approximately 16 percent of our total consolidated assets. We expect that 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 Entitys 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.
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Holders of our common stock may not receive dividends in the amount identified in guidance or any dividends at all.
We may not have sufficient cash flow each quarter to make dividends or maintain current or expected levels of dividends. The actual amount of cash we dividend will depend on the following factors, some of which are beyond our control, among others:

The
amount of cash that WPZ and our other subsidiaries and the Partially Owned Entities distribute to us;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 partners 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 WPZs 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 amount of cash we generate from our operations, which is subject to prices we obtain for our services, the prices of natural gas, NGLs and olefins, and the volumes of gas we process and NGLs and olefins we fractionate and store, and our operating costs;

The level of capital expenditures we makeexisting and new competition in our businesses or from alternative fuel sources, such as electricity, coal, fuel oils, or nuclear energy;
The restrictions contained in our indentures and Credit Facility and our debt service requirements;

The cost of acquisitions, if anyNatural 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;
Fluctuations in our working capital needs; and

Our ability to borrow.
Our cash flow depends heavily on the earnings and distributions of WPZ
Our partnership interest 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 WPZs 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 investments or acquisitions. Other companies with which we compete 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. There can be no assurance that we will be able to compete successfully against current and future competitors and any failure to do so 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, if 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 significant customer or supplier contracts on favorable terms is subject to a number of factors, some of which are beyond our control, including, but not limited to:
General economic, financial markets and industry conditions;

The level of existing and new competition in our businesses or from alternative fuel sources, such as electricity, coal, fuel oils, or nuclear energy.
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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.The effects of regulation on us, our customers and our contracting practices;
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General economic, financial markets and industry conditions.

The effects of regulation on us, our customers and contracting practices.
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 for which they may not be adequately insured.
. hr r prtoa ik soitdwt h ahrn,tasotn,soae rcsigadtetn fntrlgs h rcinto,tasotto n trg fNL,poesn foeis n rd i rnprainadpouto adig nldn:
Hurricanes, tornadoes, floods, fires, extreme weather conditions, and other natural disasters;

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; and

Terrorist attacks or threatened attacks on our facilities or those of other energy companies.
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 and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate, 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. IAn spite of our precautions, an event such as those described above could cause considerable harm to people or property, and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers.
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.
We are not fully insured against all risks inherent to our business, including environmental accidents. We do not maintain insurance in the type and amount to cover all possible risks of loss.
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
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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. If a significant accident or event occurs for which we are not fully insured it could adversely affect our operations and financial condition.
I
n 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.
Furthermore, any insurance company that provides coverage to us may experience negative developments that could impair their ability to pay any of our claims. As a result, we could be exposed to grea
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 WPZs Geismar olefins plant to operation following the explosion and fire at the facility on June13, 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 expecterd losses than anticipated and may have to obtain replacement insurance, if available, at a greater cost.
The occurrence of any risks not fully covered by insurance could have a material adverse eff
evels of dividends are based on numerous assumptions and estimates, including but not limited to the time required to return WPZs Geismar, Louisiana, olefins plant to operation and complete the expansion project at the facility following the explosion and fire at the plant on June13, 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 onif our business, results of operations, financial condition, cash flows and our ability to repay our debt.
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 theseour 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.
O
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 that could disrupt our busines. 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
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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.
Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts
Breaches in our information technology infrastructure or physical facilities, or other disruptions including those arising from theft, vand have a material adverse effect on our operations, financial position and results of operations.
We could be subject to penalties and fines if we fail to comply with laws governing our businesses.
Our businesses are regulated by numerous governmental agencies including, but not limited to, the FERC, the EPA and the PHMSA. Should we fail to comply with applicable statutes, rules, regulations and orders, our businesses could be subject to substantial penalties and fines. For example, under the Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act (NGA) to impose penalties for current violations of up to $1,000,000 per day for each violation and under the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, the PHMSA has civil penalty authority up to $200,000 per day, with a maximum of $2 million for any related series of violations. Any material penalties or fines under these or other statutes, rules, regulations or orders coul
alism, 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 impaeffect on our businesoperations, financial condposition, and results of operations. and cash flows.
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.
The natural gas sales, transmission and storage operations of the gas pipelines are subject to
In addition to regulation by other federal, state and local regulatory authorities. Specifically, their, under the Natural Gas Act of 1938, interstate pipeline transportation and storage service is subject to regulation by the FERC. The fFederal regulation extends to such matters as:


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

Rates, operating terms, and conditions of service, including initiation and discontinuation of service;

The types of services the gas pipelines may offer their customers;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; and

Market manipulation in connection with interstate sales, purchases or transportation of natural gas.
Under the NGA, the FERC has authority to regulate providers of natural gas pipeline transportation and storage services in interstate commerce, and such providers may only charge rates that have been determined to
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be just and reasonable by the FERC. In addition, the FERC prohibits providers from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
Regulatory actions in these areas 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.
The rates, terms and conditions for interstate gas pipeline services are set forth in FERC-approved tariffs. Any successful complaint or protest against the rates of the gas pipelines could have an adverse impact on their revenues associated with providing transportation services.
We are subject to risks associated with climate change and the regulation of greenhouse gas emissions.
Climate change and the costs that may be associated with its impacts and with the regulation of emissions of greenhouse gases (GHGs) have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks.
In addition, legislative and regulatory responses related to GHGs and climate change create the potential for financial risk.
The U.S.Environmental Protection Agency (EPA) has issued a final determination that six GHG emissions are a threat to public safety and welfare and implemented permitting for new and/or modified large sources of GHG emissions. Increased public awareness and concern over climate change may result in additional state, regional and/or federal requirements to reduce or mitigate GHG emissions. The U.S. Congress and certain states have for some time been considering various forms of legislation related to GHG emissions and additional regulation of GHG emissions in our industry may be implemented under existing Clean Air Act programs. There have also been international efforts seeking legally binding reductions in emissions of GHGs.
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 any GHGemissions 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. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products and services by making our products and services less desirable than competing sources of energy.
Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs, liabilities and expenditures that could exceed current expectations.
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 a result, we may be required to make substantial expenditures that could exceed current 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.
Various governmental authorities, including the EPA, the U.S. Department of the Interior, the Bureau of Indian Affairs and analogous state agencies and tribal governments, have the power to enforce compliance with
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these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and 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.
There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to our handling of the products as they are gathered, transported, processed, fractionated and stored, air emissions related to our operations, historical industry operations, waste and waste disposal practices, and the prior use of flow meters containing mercury. 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 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. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.
Our business may be adversely affected by changed regulations and increased costs due to stricter pollution control requirements or liabilities resulting from noncompliance with required operating or other regulatory permits. We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretation of those laws and regulations. If the interpretation of the laws and regulations themselves change, our assumptions and expectations may also change and any new capital costs incurred to comply with such changes may not be recoverable under our regulatory rate structure or our customer contracts. We might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our business, financial condition, results of operations and cash flows.
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.
Increased regulation of energy extraction activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, which could decrease the volumes of natural gas and other products that we transport, gather, process and treat.
Hydraulic fracturing, a practice involving the injection of water, sand and chemicals under pressure into tight geologic formations to stimulate oil and natural gas production, is currently exempt from federal regulation pursuant to the federal Safe Drinking Water Act (except when the fracturing fluids or propping agents contain diesel fuels). However, public concerns have been raised related to its potential environmental impact and there have been recent initiatives at the federal, state and local levels to regulate or otherwise restrict the use of hydraulic fracturing. Several states have adopted regulations that impose permitting, disclosure and well-completion requirements on hydraulic fracturing operations. The EPA has also announced regulatory and
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enforcement initiatives related to hydraulic fracturing and other natural gas extraction and production activities. We cannot predict whether any additional federal, state or local laws or regulations will be enacted in this area and if so, what their provisions would be. If new regulations are imposed related to oil and gas extraction, or if additional levels of reporting, regulation or permitting moratoria are required or imposed 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.
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 increased regulations being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations and court proceedings. 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 or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current legal proceedings or other matters against us, including environmental matters, suits, regulatory appeals and similar matters might result in adverse decisions against us. 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, new laws and regulations might be adopted or become applicable to us, our facilities or our customers, and future changes in laws and regulations could have a material adverse effect on our financial condition, results of operations, cash flows and ability to pay interest on our indebtedness. For example, various legislative and regulatory reforms associated with pipeline safety and integrity have been proposed or enacted, including the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 enacted on January3, 2012. This law will result in the promulgation of new regulations to be administered by PHMSA affecting the operations of our gas pipelines including, but not limited to, requirements relating to pipeline inspection, installation of additional valves and other equipment and records verification. These reforms and any future changes in related laws and regulations could significantly increase our costs and impact our operations. In addition, the FERC or competition in our markets may not allow us to recover such costs in the rates we charge for our services.
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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 they 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 and quarterly 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 capital markets, the credit 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 reduced energy demand and lower prices for our products and services, increased difficulty in collecting amounts owed to us by our customers and a reduction in our credit ratings (either due to tighter rating standards or the negative impacts described above), which could reduce our access to credit markets, raise the cost of such access or require us to provide additional collateral to our counterparties. 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 governments 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 could impact our liquidity, access to capital and our costs of doing business, and independent third parties outside of our control determine our credit ratings.
A downgrade of our credit ratings might increase our cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:
Relationships with affiliated companies who are involved in marketing functions of the natural gas business;

Economic downturns;

Deteriorating capital market conditions;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
27
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 GHGcompliance 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
28
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 governments 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 December31, 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:


Declining market prices for natural gas, NGLs, olefins, oil and other commodities;

Terrorist attacksMake it more difficult for us to satisfy our threaobligations with respect to our indebtedned attacks oss, which could in otur facilities or those of other energy companies; andn result in an event of default on such indebtedness;

The overall health of the energy industry, including the bankruptcy or insolvency of other companies.
Credit rating agencies perform independent analysis when assigning credit ratings. This analysis includes a number of criteria including, but not limited to, 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 not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the ratings agencies, and no assurance can be given that we will maintain our current credit ratings.
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. We cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers and counterparties creditworthiness. 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 our leverage may affect our future financial and operating flexibility.
Our total outstanding long-term debt (including current portion) as of December31, 2012, was $10.7 billion.
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;
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Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes;

Adversely affect our ability to pay cash dividends to stockholders;

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, general corporate purposes or other purposes;

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 transacRequire 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, that might otherwise be considered beneficial to us;e payments of dividends, general corporate purposes or other purposes;
30


Place us at a competitive disadvantage compared to our competitors that have proportionately less debt.
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, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control and may differ materially from our current assumptions. 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 Managements Discussion and Analysis of Financial Condition and Results of Operations Managements Discussion and Analysis of Financial Condition and Liquidity.
We are not prohibited under our indentures from incurring additional indebtedness. Our incurrence of significant additional indebtedness would exacerbate the negative consequences mentioned above, and could adversely affect our ability to repay our existing indebtedness.
Institutional knowledge residing with current employees nearing retirement eligibility or with our former employees might not be adequately preserved.
In certain areas of our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age 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.
We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets.
Our portfolio of derivative and other energy contracts may consist of wholesale contracts to buy and sell commodities, including contracts for natural gas, NGLs, olefins, and other commodities that are settled by the
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delivery of the commodity or cash throughout the United States. If the values of these contracts change in a direction or manner that we do not anticipate or cannot manage, it could negatively affect our results of operations. In the past, certain marketing and trading companies have experienced severe financial problems due to price volatility in the energy commodity markets. In certain instances this volatility has caused companies to be unable to deliver energy commodities that they had guaranteed under contract. If such a delivery failure were to occur in one of our contracts, we might incur additional losses to the extent of amounts, if any, already paid to, or received from, counterparties. In addition, in our businesses, we often extend credit to our counterparties. Despite performing credit analysis prior to extending credit, we are exposed to the risk that we might not be able to collect amounts owed to us. If the counterparty to such a transaction fails to perform and any collateral that secures our counterpartys obligation is inadequate, we will suffer a loss. Downturns in the economy or disruptions in the global credit markets could cause more of our counterparties to fail to perform than we expect.
Our risk management and measurement systems and hedging activities might not be effective and could increase the volatility of our results.
The systems we use to quantify commodity price risk associated with our businesses might not always be followed or might not always be effective. Further, such systems do not in themselves manage risk, particularly risks outside of our control, and adverse changes in energy commodity market prices, volatility, adverse correlation of commodity prices, the liquidity of markets, changes in interest rates and other risks discussed in this report might still adversely affect our earnings, cash flows and balance sheet under applicable accounting rules, even if risks have been identified.
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 contracts 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.
Our use of hedging arrangements through which we attempt to reduce the economic risk of our participation in commodity markets could result in increased volatility of our reported results. Changes in the fair values (gains and losses) of derivatives that qualify as hedges under generally accepted accounting principles (GAAP), to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as hedges under GAAP, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to us has occurred during the applicable period.
The impact of changes in market prices for NGLs and natural gas on the average prices paid or received by us may be reduced based on the level of our hedging activities. These hedging arrangements may limit or enhance our margins if the market prices for NGLs or natural gas were to change substantially from the price established by the hedges. In addition, our hedging arrangements expose us to risk of financial loss in certain circumstances, including instances in which:

Volumes are less than expected;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 Managements Discussion and Analysis of Financial Condition and Results of Operations Managements 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 contracts 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 July2010, 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
31
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 subsidiarys 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 partners 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 December31, 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 EPAs investigation of Transcos compliance with the Clean Air Act. On March28, 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 February12, 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, Item8. 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 February21, 2014, are listed below.


The hedging instrument is not perfectly effective in mitigating the risk being hedged; and

The counterparties to our hedging arrangements fail to honor their financial commitments.
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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 July2010, federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act) was enacted. The Dodd-Frank Act provides for new 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 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 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 subsidiarys 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 partners affiliates, including us, on the other hand). Any liability resulting from such claims could be material.
Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.
Regulators and legislators continue to take a renewed look at accounting practices, financial disclosures, and companies relationships with their independent public accounting firms. It remains unclear what new laws or
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regulations will be adopted, and we cannot predict the ultimate impact that any such new laws or regulations could have. In addition, the Financial Accounting Standards Board, the SEC or the FERC could enact new accounting standards or the FERC could issue rules that might impact how we are required to record revenues, expenses, assets, liabilities and equity. Any significant change in accounting standards or disclosure requirements could have a material adverse effect on our business, results of operations, and financial condition.
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 delays in construction and interruption of business, as well as risks of war, expropriation, nationalization, 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 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 Internal Revenue Service (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 Internal Revenue Code of 1986 (the Code), except for cash payments made to our stockholders in lieu of fractional shares of WPX common stock. In
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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 December31, 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.

Item1B.
Unresolved Staff Comments
Not applicable.
Alan S. Armstrong
Director, Chief Executive Officer, and President


Item2.
Properties
Please read Business for a description of the location and general character of our principal physical properties. We generally own 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.
Age: 51

Item3.
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 EPAs investigation of Transcos
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compliance with the Clean Air Act. On March28, 2008, the EPA issued notices of violation alleging violations of Clean Air Act requirements at these compressor stations. Transco met with the EPA in May 2008 and submitted a response denying the allegations in June 2008. In May 2011, Transco provided additional information to the EPA pertaining to these compressor stations in response to a request they had made in February 2011. In August 2010, the EPA requested, and Transco provided, similar information for a compressor station in Maryland.
In September 2011, the Colorado Department of Public Health and Environment proposed a penalty of $301,000 for alleged violations of the Colorado Clean Water Act related to excavation work being done for our Crawford Trail Pipeline. Under a settlement reached with the agency in November 2011, we agreed to pay $275,000, which was paid in November 2012.
Other
The additional information called for by this item is provided in Note17 of the Notes to Consolidated Financial Statements included under Part II, Item8. Financial Statements of this report, which information is incorporated by reference into this item
Position held since January 2011.
Item4.
Mine Safety Disclosures
Not applicable.
Executive Officers of the Registrant
The name, age, period of service, and title of each of our e
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 oOfficers as of February22, of the general partner of WPZ, where he served as Senior Vice President - Midstream from 20130, are listed belownd Chief Operating Officer and a director from 2005.
Alan S. Armstrong
Director, Chief Executive Officer, and President

Age: 50

Position held since January 2011.Francis (Frank) E. Billings
Senior Vice President Corporate Strategic Development


From February 2002 until January 2011 Mr.Armstrong was Senior VicePresident-Midstream and acted as President of our midstream business. From 1999 to February 2002, he was VicePresident, Gathering and Processing for our midstream business. From 1998 to 1999 he was Vice President, Commercial Development for Midstream. Mr.Armstrong served as Senior Vice President Midstream of the general partner of WPZ and Chief Operating Officer from 2005 until February 2010. Mr. Armstrong also serves as Chairman of the Board and Chief Executive Officer of WilliamsPartners GP LLC, the general partner of WPZ. Since December 2012, Mr. Armstrong has served as a director of Access Midstream Partners GP, L.L.C., the general partner of Access Midstream Partners, L.P. (a midstream natural gas service provider), in which we own an interest.
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Age: 51

Francis (Frank) E. Billings
Senior Vice President Northeast G&P
Position held since January 2014.

Age: 50Mr. 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.

Position held since January 2013.

Mr. Billings served as a Vice President of our midstream gathering and processing business from January 2011 until January 2013 and as Vice President, Business Development from August 2010 to January 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 July 2009 until July 2010.From July 2008 to June 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. Since January 2013, Mr.Billings has also served as Senior Vice President Northeast G&P of the general partner of WPZ.

Allison G. Bridges
Senior Vice President West

Age: 534

Position held since January 2013.

Ms. Bridges served as the Vice President and General Manager of Williams Gas Pipeline
- West from July 2010 until January 2013.From May 2003 to July 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. Since January 2013, Ms. Bridges hais also served as the Senior Vice President - West of Williams Partners GP LLC, the general partner of WPZ. Ms. Bridges has served as a member of the Management Committee of Northwest Pipeline since 2007.
35



Donald R. Chappel
Senior Vice President and Chief Financial Officer

Age: 612

Position held since April 2003.

Prior to joining us, Mr. Chappel held various financial, administrative and operational leadership positions.
Mr. Chappel also serves as ChiefFinancial Officer and a director of Williams Partners GP LLC, the general partner of WPZ. Since December 2012, Mr. Chappel has served as a director of Access Midstream Partners GP, L.L.C., the general partner of Access Midstream Partners, L.P. (a midstream natural gas service provider)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 October 2007. He2007. Mr. Chappel was ChiefFinancial Officer from August 2007 and a director from January 2008 of Williams Pipeline GP LLC, the general partner of Williams Pipeline Partners L.P., until its merger with WPZ in August 2010. Mr. Chappel is a director of SUPERVALU, Inc. (a grocery and pharmacy company), chairman of its finance committee and a member of its audit committee.
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Table of Contents
. Mr. Chappel also serves as ChiefFinancial 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.



RbnL wn
Senior Vice President and Chief Administrative Officer

Age: 578

Position held since April 2008.

From
May 2004 to April 2008, Ms.Ewing was Vice President of Human Resources. Prior to joining Williams, Ms.Ewing worked at MAPCO, which merged with Williams in April 1998. She1998. Ms. Ewing began her career with Cities Service Company in 1976.



Rr .Mle
Senior Vice President Atlantic Gulf

Age: 523

Position held since January 2013.

From
January 2011 until January 2013, Mr. Miller served as Senior Vice President - Midstream of us and the general partner of WPZ, acting as President of our midstream business. HeMr. Miller was a VicePresident of our midstream business from May 2004 until January 2011. Mr. Miller also serves as a director and as Senior VicePresident - Atlantic-Gulf of the general partner of WPZ. Mr. Miller has served as a member of the Management Committee of Transco since 2013.
36


Craig L. Rainey
Senior Vice President and General Counsel

Age: 60

Position held since January 2012.Fred E. Pace
Senior Vice President E&C (Engineering and Construction)


Mr. Rainey has served as Senior Vice President and General Counsel since January 2012. From February 2001 to January 2012, Mr. Rainey served as an Assistant General Counsel of Williams, primarily supporting our midstream business and former exploration and production business. He joined Williams in 1999 as a senior counsel and has practiced law since 1977. He has also served as the General Counsel of the general partner of WPZ since January 2012.Age: 52

Ted T. Timmermans
Vice President, Controller, and Chief Accounting Officer
Position held since January 2013.

Age: 56From 2011 until 2013, Mr. Pace served Williams in project engineering and development roles, including service as VicePresident 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.

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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Randy M. Newcomer
Interim
Brian L. Perilloux
Senior Vice President NGL & Petchem ServiOperational Excellences

Age: 6052

Position held since January 2013.

Mr. NewcomerPerilloux served as a Vice President Operations Performance of our midstream business since 2010, managing since 2011 the team that reorganized our senior management structureof our midstream business from 2011 until 2013. From 20047 to 2010, he was a vice president for William1, Mr. Perilloux served in various rolefins and natural gas liquids business. From 1996 to 2004, he was a vice president for refining and marketing operations of Williams or MAPCO Inc. which merged with Williams in 1998. Since January 2013, Mr. Newcomer hass 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 serveds as Interim Senior Vice President NGL & Petchem Servi- Operational Excellences ftegnrlprnro P.
Fred E. Pace
Senior Vice President E&C (Engineering and Construction)

Age: 51

Position held since January 2013.Craig L. Rainey
Senior Vice President and General Counsel


From January 2011 until January 2013, Mr. Pace served Williams in project engineering and development roles, including service as VicePresident Engineering and Construction for our midstream business. From December 2009 to January 2011, Mr. Pace was the managing member of PACE Consulting, LLC (an engineering and consulting firm serving the energy industry). In August 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 December 2009. Mr. Pace has over 25 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. Since January 2013, Mr. Pace has also served as Senior Vice President E&C of the general partner of WPZ.Age: 61

Brian L. Perilloux
Senior Vice President Operational Excellence
Position held since January 2012.

Age: 51Mr. 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.

Position held since January 2013.

Mr. Perilloux served as a Vice President of our midstream business from January 2011 until January 2013. From August 2007 to January 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. Since January 2013, Mr.Perilloux has also served as Senior Vice President Operational Excellence of Williams Partners GP LLC, the general partner of WPZ.
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James E. Scheel
Senior Vice President
Corporate Strategic DevelopmentSenior 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 VicePresident 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.
37



Age: 48Ted T. Timmermans
Vice President, Controller, and Chief Accounting Officer


Position held since February 2012.Age: 57

From January 2011 until February 2012, Mr. Scheel served as VicePresident of Business Development for our midstream business. He joined Williams in 1988 and has served in leadership roles in business strategic development, engineering and operations, our NGL business, and international operations. Since December 2012, Mr.Scheel has served as a director of Access Midstream Partners GP,L.L.C., the general partner of Access Midstream Partners, L.P. (a midstream natural gas service provider), in which we own an interest. Mr. Scheel also serves as a director and as Senior Vice President Corporate Strategic Development of the general partner of WPZ.
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PART II
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.
38
PART II
Item 5.
Market for Registrants 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, 20134, we had approximately 8,843405 odr frcr forcmo tc.Tehg n o ae rc ags(e okSokEcag opst rnatos n iied elrdb ure o aho h attoyasaea olw:

2012
2011

Quarter
High
Low
Dividend
High
Low
Dividend

1st2013

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
$
31.77
$
24.26
$
0.125

2nd
$
Second Quarter
34.63
$
27.25
$
0.30
$
33.47
$
27.92
$
0.20

3rd
$
Third Quarter
35.39
$
28.47
$
0.3125
$
33.16
$
23.46
$
0.20

4th
$
Fourth Quarter
37.56
$
30.55
$
0.325
$
33.11
$
21.90
$
0.25
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 January1, 20089. 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.



2007
2008
2009
2010
2011
2012
2013

The Williams Companies, Inc.
100.0
41.2
61.7
74.0
149.8
179.8
246.4

3101.4
128
.9
381
.

S&P 500 Index
100.0
63.0
79.7
91.7
93.6
10
126.5
145.5
148.6
172.3
22
8.60

Bloomberg U.S. Pipelines Index
100.0
61.1
86.6
106.5
146.8
166.6
The information presented in the performance graph has been recast to reflect the WPX spin-off completed on December31, 2011.
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141.7
174.3
240.3
272.6
302.7
39
Item 6. Selected Financial Data The following financial data at December31, 2013 and 2012, and for each of the three years in the period ended December31, 2013, should be read in conjunction with the other financial information included in Part II, Item7, Managements Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item8, Financial Statements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting records.


Item6.
Selected Financial Data
The following financial data at December31, 2012 and 2011, and for each of the three years in the period ended December31, 2012, should be read in conjunction with the other financial information included in Part II, Item7, Managements Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item8, 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
2008

(Millions, except per-share amounts)

Revenues
$
6,860
$
7,486
$
7,930
$
6,638
$
5,278
$
6,904

Income (loss) from continuing operations (1)
679
929
1,078
271
346
682

Amounts attributable to The Williams Companies, Inc.:

Income (loss) from continuing operations (1)
441

723
803
104
206
528

Diluted earnings (loss) per common share:

Income (loss) from continuing operations (1)
0.64

1.15
1.34
0.17
0.35
0.90

Total assets at December31 (2)(3)
27,142
24,327
16,502
24,972
25,280
26,006

Short-term notes payableCommercial paper and long-term debt due within one year at December31 (4)
226

1
353
508
17
18

Long-term debt at December31 (3)
11,353
10,735
8,369
8,600
8,259
7,683

Stockholders equity at December31 (2)(3)
4,864
4,752
1,296
6,803
7,990
7,983

Cash dividends declared per common share
1.438
1.196
0.775
0.485
0.44
0.43_________


(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. See Note 5 of Notes to Consolidated Financial Statements for further discussion of asset sales and other accruals in 2012, 2011, and 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.
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(4)
The increase in 2013 reflects borrowings under WPZs commercial paper program initiated in 2013.
40
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations General We are an energy infrastructure company focused on connecting North Americas 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 FERCs 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, Item8 of this document.
41
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-i n-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 December31, 2013 , changed unfavorably by $282 million compared to the year ended December31, 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 June13, 2013, an explosion and fire occurred at WPZs 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;


Item7.
Managements Discussion and Analysis of Financial Condition and Results of Operations
General
We are an energy infrastructure company focused on connecting North Americas significant hydrocarbon resource plays to growing markets for natural gas, natural gas liquids (NGLs), and olefins. Our operations span from the deepwater Gulf of Mexico to the Canadian oil sands and include midstream gathering and processing assets, an olefins production facility, and interstate natural gas pipelines held through our significant investment in Williams Partners L.P. (NYSE: WPZ), of which we currently own approximately 70 percent, including the general partner interest. We also process oil sands offgas in Canada and hold an overall approximate 25 percent interest in Access Midstream Partners, L.P. (NYSE: ACMP), including a 50 percent interest in the general partner and the associated incentive distribution rights. ACMP owns and operates midstream assets located in the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara and Utica shales and Mid-Continent region.
We are organized into the Williams Partners, Williams NGL& Petchem Services, and Access Midstream Partners reportable segments. All remaining business activities are included in Other. (See Note 1 of Notes to Consolidated Financial Statements for further discussion of these segments.)
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, Item8 of this document.
Acquisitions
In February 2012, WPZ completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC (Laser Acquisition). These entities primarily own the Laser Gathering System, which is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as 10 miles of gathering lines in southern New York. This acquisition represents a strategic platform to enhance WPZs expansion in the Marcellus Shale by providing our customers with both operational flow assurance and marketing flexibility. (See Results of Operations Segments, Williams Partners.)
In April 2012, WPZ completed the acquisition of 100 percent of the ownership interest in Caiman Eastern Midstream, LLC (Caiman Acquisition). The acquired entity operates a gathering and processing business in northern West Virginia, southwestern Pennsylvania and eastern Ohio. WPZ believes this acquisition will provide it with a significant footprint and growth potential in the NGL-rich portion of the Marcellus Shale. (See Results of Operations Segments, Williams Partners.)
In December 2012, we made significant investments in Access Midstream Partners GP, L.L.C. (Access GP) and Access Midstream Partners, L.P. (ACMP) (collectively referred to as Access Midstream Partners). We now own a 50 percent indirect interest in Access GP which holds the 2 percent general partner interest in ACMP and incentive distribution rights. In addition, we hold approximately 24 percent limited partner interest in ACMP for a combined ownership interest of approximately 25 percent of ACMP. 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. (See Results of Operations Segments, Access Midstream Partners.)
Dividend Growth
We increased our quarterly dividends from $0.25 per share in the fourth quarter of 2011 to $0.325 per share in the fourth-quarter of 2012. 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 $0.33875 per share for the first quarter of 2013 and we expect a 20 percent annual increase in total dividends in both 2013 and 2014.
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Overview
During the second quarter 2012, NGL margins declined sharply largely attributable to a record-warm winter, a slowing global economy, and growing NGL supplies. The downward trend of per-unit NGL margins leveled-off during the second-half of 2012. We have been impacted by this environment as our 2012 income (loss) from continuing operations attributable to The Williams Companies, Inc. decreased by $80 million compared to 2011. This decrease is primarily due to an unfavorable change in operating income (loss) and the absence of certain income tax provision benefits recognized in 2011, partially offset by the absence of early debt retirement costs incurred in 2011. See additional discussion in Results of Operations.
Our net cash provided by operating activities for 2012 decreased $1.604 billion compared to 2011, largely due to the absence of operating cash flows from our former exploration and production business and lower operating results.
Abundant and low-cost natural gas reserves in the United States continue to drive strong demand for midstream and pipeline infrastructure. We believe we have successfully positioned our energy infrastructure businesses for significant future growth, as highlighted by the following accomplishments during 2012 through the present:
Recent Events
In addition to the previously discussed acquisitions, we note the following:

In February 2012, we announced a new interstate gas pipeline project. The new 120-mile Constitution Pipeline will connect Williams Partners gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. We currently own 51 percent of Constitution Pipeline with two other parties holding 25 percent and 24 percent, respectively. This project, along with the newly acquired Laser Gathering System and our Springville pipeline, are key steps in Williams Partners strategy to create the Susquehanna Supply Hub, a major natural gas supply hub in northeastern Pennsylvania. In April 2012, we began the Federal Energy Regulatory CommissGeneral liability coverage with per-occurrence and aggregate annual limits of $610 million and retentions (FERC) pre-filing process for the Constitution Pipeline and expect to file a FERC application during the second quarter of 2013.deductibles) of $2 million per occurrence;

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

In April 2012, we issued 30million 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 WPZs Caiman Acquisition Workers compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence.
42
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) expensenet 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 Transcos 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 pipelines 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 April1, 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 producers 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 43Mbbls/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 Transcos 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 95Mdth/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 Transcos 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 August31, 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 March1, 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 Transcos 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
.
In April 2012, WPZ completed an equity issuance of 10million common units representing limited partner interests at a price of $54.56 per unit. Subsequently, WPZ sold an additional 973,368 common units for $54.56 per unit to the underwriters upon the underwriters exercise of their option to purchase additional common units. The net proceeds were used for general partnership purposes, including funding a portion of the cash purchase price of WPZs Caiman Acquisition.

In July 2012, Transcontinental Gas Pipe Line Company, LLC (Transco) issued $400 million of 4.45 percent senior unsecured notes due 2042 to investors in a private debt placement. A portion of these proceeds was used to repay Transcos $325 million 8.875 percent senior unsecured notes that matured
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on July15, 2012. 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 2012.45
Williams NGL& Petchem Services Canadian PDH Facility During the first quarter of 2013, we announced plans to build Canadas 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 180million 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
46
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:


In July 2012, WPZ formed Caiman Energy II, LLC with Caiman Energy, LLC and others to develop large-scale natural gas gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and northwest Pennsylvania. As a result, WPZ plans to contribute $380 million through 2014 to fund a portion of Blue Racer Midstream, a joint project formed in December 2012 between Caiman Energy II, LLC and another party.

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

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

In November 2012, we contributed to WPZ our 83.3 percent undivided interest and operatorship of an olefins-production facility located in Geismar, Louisiana, along with our refinery grade propylene splitter and pipelines in the Gulf region. These businesses were previously reported through our Williams NGL& Petchem Services segment; however, they are now reported in our Williams Partners segment and prior period segment disclosures have been recast for this transaction. WPZ funded substantially all of the transaction with the issuance of limited partner units to us.Unexpected significant increases in capital expenditures or delays in capital project execution;

In November 2012, we completed the purchase of 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 are expected to be placed into service beginning in late 2014.

In December 2012, we issued approximately 53million 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 our investment in Access Midstream Partners. (See Note 2 of Notes to Consolidated Financial Statements).Lower than anticipated or delay in receiving insurance recoveries associated with the Geismar Incident;

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 fund a portion of our investment in Access Midstream Partners. (See Note 2 of Notes to Consolidated Financial Statements).

In January 2013, WPZ agreed to sell a 49 percent ownership interest in its Gulfstar FPS project to a third party. The transaction is expected to close in second-quarter 2013, at which time we expect the third party will contribute $225 million to fund its proportionate share of the project costs, following with monthly capital contributions to fund its share of ongoing construction.
Outlook for 2013
Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas, natural gas products, and crude oil that exists in North America. We seek to accomplish this through further developing our scale positions in current key markets and basins and entering new growth markets and basins where we can become the large-scale service provider. We will maintain a strong commitment to operational excellence and customer satisfaction. We believe that accomplishing these goals will position us to deliver an attractive return to our stockholders.
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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.
In light of the above, our business plan for 2013 continues to reflect both significant capital investment and dividend growth. Our planned consolidated capital investments for 2013 total approximately $4.275 billion, of which we expect to fund primarily through cash on hand, cash flow from operations, and debt and equity issuances by WPZ. We also expect 20 percent growth in total 2013 dividends, which we expect to fund primarily with distributions received from WPZ. Our structure is designed to drive lower capital costs, enhance reliable access to capital markets, and create a greater ability to pursue development projects and acquisitions.
Potential risks and/or obstacles that could impact the execution of our plan include:
Limited availability of capital due to a change in our financial condition, interest rates, market or industry conditions;

General economic, financial markets, or industry downturn;

Availability of capitalLower than expected distributions, including IDRs, from WPZ. WPZs liquidity could also be impacted by a lack of adequate access to capital markets to fund its growth;
Lower than expected levels of cash flow from operations;

Counterparty credit and performance risk;

Decreased volumes from third parties served by our midstream businesses;

Unexpected significant increases in capital expenditures or delays in capital project executionDecreased volumes from third parties served by our midstream business;


Lower than anticipated energy commodity prices and margins
;
Lower than anticipated energy commodity prices and margins;

Changes in the political and regulatory environments;

Physical damages to facilities, especially damage to offshore facilities by named windstorms.
We continue to address these risks through maintaining a strong financial position and ample liquidity, as well as managing a diversified portfolio of energy infrastructure assets.
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 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 8 of Notes to Consolidated Financial Statements.
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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.

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 Discoverys Keathley Canyon Connector lateral in the fourth quarter of 2014.
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Eminence Storage Field leak
On December28, 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 Transcos 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 Transcos Leidy Southeast Expansion project to expand our existing natural gas transmission system from the Marcellus Shale production region on Transcos 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 Transcos 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 Transcos 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 Transcos 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 Ones production handling capacity related to the Gunflint Development is expected to be completed in mid-2016, dependent on the producers 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 June2014. The expansion is expected to increase the facilitys ethylene production capacity by 600million 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 Discoverys existing 30-inch offshore natural gas transmission system. The gas will be processed at Discoverys Larose Plant and the NGLs will be fractionated at Discoverys 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 Canadas 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
52
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.



BnftCs
Benefit Obligation

One-
Percentage-
Point
Increase
One-

Percentage-
Point
Decrease
One-

Percentage-
Point
Increase
One-

Percentage-
Point
erae
(Millions)

Pension benefits:

Discount rate
$
(86
)
$
97
$
(1
148
)
$
17533

Expected long-term rate of return on plan assets
(101
)
101

Rate of compensation increase
2
(1
)
97
(
76
)

Other postretirement benefits:

Discount rate
(41
1
(20

)
5
(42
)
53
24

Expected long-term rate of return on plan assets
(2
)
2

Assumed health care cost trend rate
5
(4
)
7
(
5
)
46
(38
)
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 ten10 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 20123, the benefit plans assets reflected strong equity performance coupled with modestas well as negative returns from the fixed income strategies. While the 20123 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 had been 7.5was 6.3 percent since 20102. In 20123, we reduced our expected long-term rate of return on pension assets to 6.35.9 percent. This reduction was implemented due to a downward trend in long-term capital market expectations and a more conservative asset allocation in the investment portfolio reflecting some shift to more fixed income securities relative to equity securities. The 20123 actual return on plan assets for our pension plans was approximately 12.15.5 percent. The ten10-year average rate of return on pension plan assets through December 20123 was approximately 6.85.7 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 December31 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
53
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 81 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 declinincreased during 20123 by 5125 basis points, which significantly contributed to the actuarial lossgain of $98173 million in the current year.
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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 and Intangible Assets
At December31, 20123 , our Consolidated Balance Sheet includes $ 6496 million of goodwill and $1.7 billion in intangible assets related to the Laser and Caiman Acquisitions, which were completed earlier this year.
Goodwill
. We performed our annual assessment of goodwill for impairment as of October1. All of our goodwill is allocated to WPZs midstreamNortheast gathering and processing business (the reporting unit). In our evaluation, our estimate of the fair value of the reporting unit significantly exceeded its carrying value by 15 percent, including goodwill, and thus no impairment loss was recognized in 2012. If the carrying value of the reporting unit had exceeded its fair value, a computation of the implied fair value of the goodwill would have been compared with its related carrying value. If the carrying value of the reporting unit goodwill had exceeded the implied fair value of that goodwill, an impairment loss would have been recognized in the amount of the excess.
The fair value of WPZs midstream business was estimated by both an income approach utilizing discounted cash flows and a market approach utilizing EBITDA multiples.
Other intangible assets
We evaluate other intangible assets for both changes in the expected remaining useful lives and impairment when events or changes in circumstances indicate, in our managements judgment, that the estimated useful lives have changed or the carrying value of such assets may not be recoverable. Changes in an estimated remaining useful life would be reflected prospectively through amortization over the revised remaining useful life. When an indicator of impairment has occurred, we compare our managements estimate of undiscounted future cash flows attributable to the intangible assets
3 . The fair value of WPZs 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 December31, 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 managements 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 assetsinvestment to determine whether an impairment has occurred and we apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. I. 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 indicatorsive of potential impairmenan other-than-temporary decline in value will vary by investment, butmyicue

Laws prohibiting the production of reserves in the areas where our assets from the Laser and Caiman Acquisitions operate;

The development of alternative energy sources that would halt the production of reserves in these areas; orA significant or sustained decline in the market value of a publicly-traded investee;

The loss of or failure to renew customer contracts.A significant portion of the value allocated to these contracts in our purchase price allocation was based on our assumptions regarding our ability and intent to renew or renegotiate existing customer contracts. (See Note 2 of Notes to Consolidated Financial Statements.)
We have not evaluated our intangible assets for impairment as of December31, 2012, as there were no indicators of potential impairment.
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Equity-method Investments
At December 31, 2012, our Consolidated Balance Sheet includes approximately $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 managements 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 declLower than expected cash distributions from investees (includineg in the market value of a publicly-traded investeecentive distributions);
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; and,

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.
54
No impairments of investments accounted for under the equity method have been recorded for the year ended December 31, 2012.
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3. Capitalized project development costs As of December31, 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 December31, 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.
55

Results of Operations

Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three years ended December31, 20123 . The results of operations by segment are discussed in further detail following this consolidated overview discussion.



Years Ended December31,

2013
$Change from 2012*
%Change from 2012*
2012
$Change
from
2011*
%Change

from
01
2011
$Change
from
2010*
%Change
from
2010*
2010

(Millions)

Revenues:

Service revenues
$
2,939
+210
+8%
$
2,729
+197
+8
% $
2,532
+173
+7
%
$
2,359

Product sales
3,921
-836
-18%
4,757
-641
-12
% 5,398
+1,119
+26
%
4,279


Total revenues
6,860
7,486
7,930
6,638


Costs and expenses:

Product costs
3,027
+469
+13%
3,496
+438
+11
% 3,934
-674
-21
%
3,260

Operating and maintenance expenses
1,097
-70
-7%
1,027
-37
-4
% 990
-120
-14
%
870

Depreciation and amortization expenses
815
-59
-8%
756
-95
-14
% 661
-49
-8
%
612

Selling, general, and administrative expenses
512
+59
+10%
571
-94
-20
% 477
+27
+5
%
504

Other (income) expense net
34
-10
-42%
24
-23
NM
1
-16
NM
(15
)


Total costs and expenses
5,485
5,874
6,063
5,231


Operating income (loss)
1,375
1,612
1,867
1,407

Equity earnings (losses)
134
+23
+21%
111
-44
-28
% 155
+12
+8
%
143

Interest expense
(510
)
-1
0%
(509
)
+64
+11
% (573
)
+19
+3
%
(592
)

Other investing income net
81
+4
+5%
77
+64
NM
13
-32
-71
%
45

Erydb eieetcss +271
+100
% (271
)
+335
+55
%
(606
)

Other income (expense) net
+2
+100%
(2
)
-13
NM
11
+23
NM
(12
)


Income (loss) from continuing operations before income taxes
1,080
1,289
1,202
385

Provision (benefit) for income taxes
401
-41
-11%
360
-236
-190
% 124
-10
-9
%
114


Income (loss) from continuing operations
679
929
1,078
271

Income (loss) from discontinued operations
(11
)
-147
NM
136
+553
NM
(417
)
+776
+65
%
(1,193
)


Net income (loss)
668
105 661
(922
)

Less: Net income attributable to noncontrolling interests
238
-32
-16%
206
+79
+28
% 285
-110
-63
%
175


Net income (loss) attributable to The Williams Companies, Inc.
$
430
$
859
$
376
$
(1,097
)
_______


*
+= 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.

20123 vs. 2011
2 The increase in sService revenues is primarily due to Williams Partners higher fee revenues resulting from increased gathering and processing fee revenues from higher volumes in the Marcellus Shale, including new volumes on our recently acquired gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses and higher volumes in the western deepwater Gulf of Mexico and in the Piceance basinassociated 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 20112 and 2012.
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The decrease in product sales is primarily due to Williams Partners lower NGL and olefin production revenu
3 and new rates effective during first-quarter 2013. Partially offsetting these increases areflecting an overall decrease in average per-unit sales decreased gathering and prioces, 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. In addition, Williams NGL& Petchem Services production revenues decreased primarily due to lower average per-unit sales prices.sing fee revenues driven by lower volumes in the Piceance, Four Corners, and eastern Gulf Coast areas.
56

The decrease in
pProduct costsales is primarily due to Williams Partners lower olefins feedstock costs reflecting alower NGL production revenues driven by reduced ethane recoveries and decreases in average NGL per-unit sales prices, and lower costs associated with thes well as lower olefin production of NGLrevenues primarily resulting from a decrease in average natural gas prices. Marketing purchases at Williams Partners 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. Additionally, Williams NGL& Petchem Services NGL feedstock costfrom 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 averageNGL per-unit costs.
The increase in operating and maintenance expenses is primarily due to Williams Partners increased maintenance expenses primarily associated with its new 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 operation
prices and lower crude oil and ethane volumes, partially offset by higher non-ethane volumes.
The increase in depreciation and amortization expchanges in marketing revensues is primarily associated with Williams Partners new assets acquired in 2012 (see Note 2 of Notes to Consolidated Financial Statements).
The increase in selling, general, and administrative expenses (SG&A) is primarily due to an increase at Williams Partners reflecting $23 million of acquisition and transition-related costs as well as higher employee-related and information technology expenses driven by general growth within Williams Partners 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 and is substantially offset by the absence of general corporate expenses related to the spin-off of WPX, which was completed on December31, 2011.
The unfavorabl
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 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 at Williams NGL& Petchem Services (see Notes 5 and 17 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 Midstream, LLC (Laurel Mountain), Aux Sable Liquid Products L.P. (Aux Sable) and Discovery Producer Services LLC (Discovery) equity earnings at Williams Partners primarily reflecting lower operating results of these investees and the impairment of two minor NGL processing plants at Laurel Mountain.
Interest expense decreased due to an increase in interest capitalized related to construction projects primarily at Williams Partners, as well as a decrease in interest incurred related to corporate debt retirements in December 2011, partially offset by an increase in borrowings at Williams Partners (see Note 12 of Notes to Consolidated Financial Statements) and the absence of a $14 million reduction of an interest accrual related to a litigation contingency in 2011 at Williams NGL& Petchem Services 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 at Other related to the 2010 sale of our interest in Accroven SRL. (See Note 4 of Notes to Consolidated Financial Statements.)
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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 6 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 3 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
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 was 68 expercient at December31, 2012, compared to 73 percent at December31, 2011.
2011 vs. 2010
The increase in service revenues is primarily due to higher Williams Partners gathering and processing fee revenue in the Marcellus Shale related to gathering assets acquired at the end of 2010, in the western deepwater Gulf of Mexico related to assets placed into service in late 2010, and in the Piceance basin as a result of an agreement executed in November 2010. These increases are partially offset by a decline in fee revenue in the eastern deepwater Gulf of Mexico primarily due to natural field declines. Williams Partners natural gas transportation revenues increased primarily due to expansion projects placed in service in 2010 and 2011.
The increase in product sales is primarily due to higher marketing and NGL and olefin production revenues at Williams Partners as a result of higher average energy commodity prices, partially offset by a decrease in NGL production volumes. Williams NGL & Petchem Services production revenues increased primarily resulting from higher average energy commodity prices and higher volumes.
The increase in product costs is primarily due to increased marketing purchases and olefin feedstock costs at Williams Partners primarily resulting from higher average energy commodity prices. These increases are partially offset by decreased costs associated with production of NGLs reflecting lower average natural gas prices and lower NGL production volumes at Williams Partners.
The increase in operating and maintenance expenses is due to increased maintenance expenses and higher property insurance expenses primarily at Williams Partners.
The increase in depreciation and amortiz
ced 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 administrationve expenses ( SG&A ) is primarily due to assets placed in service late in 2010, along with increased depreciation of a facility, which was idledthe absence of reorganization related costs in 2012, at Williams Partners.
The decrease in SG&A is primarily due to
nd the absence of $45 millacquisition ofand transacition costs incurred in 2010 associated with our strategic restructuring transaction.
The unfavorable change in o
2. (See Note 6 Other Income and Expenses of Notes to Consolidated Financial Statements.) Other (income) expense net within oOperating income (loss) primarily reflectsincludes the following increases to net expense:
$15 million of lower involuntary conversion gains in 2011 as compared to 2010 at Williams Partners due to insurance recoveries that are in excess of the carrying value of the assets;
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The absence of a $12 million gain in 2010 on the sale of cert$25 million accrued loss for a settlement in principle of a producer clainm assets at Williams Partnergainst us

The absence of a $6 million favorable customer settlement in 2010 at Williams NGL& Petchem Services;

$
423 million lower sales of base gas from Hester Storage field in 2011 compared to 2010 at Williams Partners.
These unfavorable changes are partially offset by:
increase in amortization expense related to our regulatory asset associated with asset retirement obligations;

$19 million of income related to a litigation contingency accrual reduction in 2011 at Williams NGL& Petchem Services as previously discussed;

$
8 million related to the net reversal of project feasibility costs from expense to capital in 2011 at Williams Partners (see Note 5 of Notes to Consolidated Financial Statements).
The favorable change in operating income (loss) generally reflects an improved energy commodity price environment in 2011 compared to 2010, increased fee revenues, and the absence of costs associated with the strategic restructuring in 2010, partially offset by higher operating costs and an unfavorable change in other (income) expense net as previously discussed.
The favorable change in equity earnings (losses) is primarily due to an increased ownership interest in Overland Pass Pipeline Company LLC (OPPL) at Williams Partners.
The unfavorable change in other investing income net is primarily due to $32 million of decreased gains recognized in 2011 related to the 2010 sale of our interest in Accroven SRL. (See Note 4 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. Early debt retirement costs in 2010 reflect costs related to corporate debt retirements associated with our first quarter 2010 strategic restructuring transaction, including premiums of $574 million.
Other (income) expense net below operating income (loss) changed favorably primarily due to an $11 million decrease in environmental accruals in 2011 as compared to 2010.
Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income, partially offset by federal settlements in 2011 and an adjustment to reverse taxes on undistributed earnings of certain foreign operations that were considered permanently reinvested. See Note 6 of Notes to Consolidated Financial Statements for a reconciliation of the effective tax rates compared to the federal statutory rate for both years.
Income (loss) from discontinued operations reflects the results of operations of our former exploration and production business as discontinued operations. (See Note 3 of Notes to Consolidated Financial Statements.)
The unfavorable change in net income attributable to noncontrolling interests reflects higher operating results at WPZ and increased noncontrolling interest ownership of WPZ as a result of WPZ equity issuances in 2010. These changes are partially offset by our greater ownership interest related to WPZs merger with Williams Pipeline Partners L.P., which was completed in 2010.
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Results of Operations Segments
Williams Partners
Our Williams Partners segment includes WPZ, our consolidated master limited partnership, which includes two interstate natural gas pipelines, as well as investments in natural gas pipeline-related companies, which serve regions from the San Juan basin in northwestern New Mexico and southwestern Colorado to Oregon and Washington and from the Gulf of Mexico to the northeastern United States. WPZ also includes natural gas gathering, processing, and treating facilities and oil gathering and transportation facilities located primarily in the Rocky Mountain, Gulf Coast, and Marcellus Shale regions of the United States. 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 December31, 2012, we own approximately 70 percent of the interests in WPZ, including the interests of the general partner, which is wholly owned by us, and incentive distribution rights.
Williams Partners ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission and midstream infrastructures where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers and utilizing our low cost-of-capital to invest in growing markets, including the deepwater Gulf of Mexico, the Marcellus Shale, the western United States, and areas of increasing natural gas demand.
Williams Partners interstate transmission and related storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERCs ratemaking process. Changes in commodity prices and volumes transported have little near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
Overview of 2012
Significant events during 2012 include the following:
Gulf Olefins production facilities acquisition
In November 2012, we contributed to WPZ 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. This business was previously reported within our Williams NGL& Petchem Services segment. The acquisition is expected to bring more certainty to cash flows that are currently exposed to volatile ethane prices by shifting the commodity price exposure to ethylene. Located south of Baton Rouge, Louisiana, the Geismar facility is a light-end NGL cracker with current feedstock volumes of 39,000 barrels per day (bpd) of ethane and 3,000 bpd of propane and annual production of 1.35 billion pounds of ethylene. With the benefit of a $350-$400 million expansion under way and scheduled for completion by late 2013, the facilitys annual ethylene production capacity will grow by 600million pounds to 1.95 billion pounds. Along with ethane, propane and ethylene, the Geismar facility also produces propylene, butadiene, and debutanized aromatic concentrate (DAC). Prior period segment disclosures have been recast for this transaction.
In the fourth quarter of 2012, we also completed the construction of a pipeline which is capable of supplying 12 Mbbls/d of ethane to our Geismar olefins production facility from Discoverys Paradis fractionator.
Caiman Acquisition
In April 2012, we completed the Caiman Acquisition for consideration valued at approximately $2.3 billion. The transition of operations is complete.
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The acquisition provides us with a significant footprint and growth potential in the natural gas liquids-rich Ohio River Valley area of the Marcellus Shale. The existing physical assets that we acquired include a gathering system, two processing facilities and a fractionator located in northern West Virginia and establish our new Ohio Valley Midstream business. In addition to the acquisition cost, we committed a large portion of our 2012 capital expenditures and continue to commit planned capital expenditures in 2013 and beyond for ongoing expansions to the gathering system, processing facilities, and fractionator, which are currently under construction. NGL pipelines are also planned. The assets are anchored by long-term contracted commitments, including 236,000 dedicated gathering acres from 10 producers in West Virginia, Ohio, and Pennsylvania.
Several projects were completed in the fourth quarter of 2012 increasing our gathering, processing and fractionating capacities. The Fort Beeler plant complex has 320million cubic feet per day (MMcf/d) of cryogenic processing capacity currently available with another 200 MMcf/d expected during the first quarter of 2013. The Moundsville fractionator is now in service with approximately 13thousand barrels per day (Mbbls/d) of NGL handling capacity. An NGL pipeline, connecting the Fort Beeler plant to the Moundsville fractionator has also been completed and is in service.
Utica Shale infrastructure project
In July 2012, WPZ formed Caiman Energy II, LLC with Caiman Energy, LLC and others to develop large-scale natural gas gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and northwest Pennsylvania.As a result, through our 47.5 percent ownership, WPZ plans to contribute $380 million through 2014 to fund a portion of Blue Racer Midstream, a joint project formed in December 2012 between Caiman Energy II, LLC and another party.
Susquehanna Supply Hub, northeastern Pennsylvania
In April 2012, we began the FERC pre-filing process for a new interstate gas pipeline project. We currently own 51 percent of Constitution Pipeline with two other parties holding 25 percent and 24 percent, respectively. We will be the operator of Constitution Pipeline. The new 120-mile Constitution Pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. The total cost of the entire project is estimated to be $680 million. We plan to place the project into service in March 2015, with an expected capacity of 650 thousand dekatherms per day (Mdth/d). The pipeline is fully subscribed with two shippers. We expect to file a FERC application during the second quarter of 2013.
In February 2012, we completed the Laser Acquisition for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments, and 7,531,381 of our common units valued at $441 million. The gathering system is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in Susquehanna County, Pennsylvania, as well as 10 miles of gathering pipeline in southern New York. The acquisition is supported by existing long-term gathering agreements that provide acreage dedications and volume commitments.
Our Springville pipeline, a 33-mile, 24-inch diameter natural gas gathering pipeline, connecting a portion of our gathering assets into the Transco pipeline, was placed into service in January 2012, and expansions were completed in the third quarter of 2012 allowing us to deliver approximately 625 MMcf/d into the Transco pipeline. This new take-away capacity allows full use of approximately 1.6 billion cubic feet per day (Bcf/d) of capacity from various compression and dehydration expansion projects to our gathering business in northeastern Pennsylvanias Marcellus Shale which we acquired at the end of 2010.
As production in the Marcellus increases and expansion projects are completed, the Susquehanna Supply Hub is expected to reach a natural gas take away capacity of 3 Bcf/d by 2015, including capacity contributions from the Constitution Pipeline.
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Mid-Atlantic Connector
In July 2011, we received approval from the FERC to expand our existing natural gas transmission system from North Carolina to markets as far downstream as Maryland. The capital cost of the project was approximately $60 million. The project was placed into service in the first quarter of 2013, increasing capacity by 142 Mdth/d.
Volume impacts in 2012
Due to third-party NGL pipeline capacity restrictions from our Four Corners plants beginning in late September and to unfavorable ethane economics in December, we reduced our recoveries of ethane in our onshore plants which resulted in 7 percent lower NGL equity sales volumes in the fourth quarter of 2012 compared to the third quarter of 2012.
Our NGL equity sales volumes for the third quarter of 2012 were modestly impacted by maintenance on the Overland Pass Pipeline for approximately 5 days. As a result of the NGL pipeline maintenance, NGL takeaway capacity from our western plants on the Overland Pass Pipeline was reduced, which forced our western plants to reduce NGL recoveries.
In the Gulf Coast, our Mobile Bay plant was shut down for 10 days due to Hurricane Isaac. The plant and offshore platforms were evacuated during the storm. Afterwards, the plant remained shut down due to flooding issues on a third-party pipeline limiting the NGL takeaway capacity. In addition, production into Devils Tower was shut-in for various time periods due to third-party hurricane related issues. These events related to Hurricane Isaac did not have a material impact to our overall NGL production or NGL equity sales.
Volatile commodity prices
Driven primarily by a sharp decline in NGL prices during the second quarter of 2012, followed by increasing natural gas prices in the latter half of 2012, average per-unit NGL margins declined during 2012 and were approximately 23 percent lower in 2012 than in 2011. Because we typically realize lower per-unit margins for ethane versus other NGLs, if we had produced the same mix of ethane and non-ethane NGLs during the fourth quarter of 2012 as we generally have in prior periods, the average per-unit margin in the fourth quarter of 2012 would have been lower. Key factors in the NGL market weakness have been high propane inventories caused by the extremely warm winter and the effect of the propane oversupply on ethane inventories and pricing. Despite an increase in natural gas prices during the latter half of 2012, we have benefited from lower natural gas prices in 2012 than in 2011, driven by abundant natural gas supplies.
NGL margins are defined as NGL revenues less any applicable British thermal unit (Btu) replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both keep-whole processing agreements, where we have the obligation to replace the lost heating value with natural gas, and percent-of-liquids agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.
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Outlook for 2013
The following factors, among others, could impact our business in 2013.
Commodity price changes
20 million write-off of development costs of an abandoned project;

We expect a decline in ethane and propane prices and an increase in natural gas prices such that our full year 2013 NGL margins are expected to be lower than our rolling five-year average and 2012 per-unit NGL margins. NGL price changes have historically tracked somewhat with changes in the price of crude oil, although NGL, crude, and natural gas prices are highly volatile, difficult to predict, and are often not highly correlated. NGL margins are highly dependent upon continued demand within the global economy. However, NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks.

While per-unit ethylene margins are volatile and highly dependent upon continued demand within the global economy, we believe that our average per-uni$12 million expense recognized in 2013 related to the portion of the Eminence abandonment regulatory asset ethylene margin will improve over 2012 levels, benefiting from higher ethylene prices and lower ethane and propane feedstock prices. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets because of our NGL-based olefins production.
Gathering, processing, and NGL sales volumes
at will not be recovered in rates. Other (income) expense net within Operating income includes the following decreases to net expense:

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

We anticipate significant growth in our natural gas gathering volu$40 million of incomes as our infrastructure grows to support drilling activities in the Marcellus Shale region.
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sociated with net insurance recoveries related to the Geismar Incident in 2013;

We anticipate equity NGL volumes in 2013 to be lower than 2012 due in part to a change in a customers contract in the onshore business from percent-of-liquids to fee-based processing, with a portion of the fee representing a share of the associated NGL margins. We also expect lower equity NGL volumes due to periods when we expect it will not be economical to recover ethane. Our expectations of sustained low natural gas prices are expected to discourage producer drilling activities in the western onshore area and unfavorably impact the supply of natural gas available to gather and process in 2013.

In Williams Partners businesses in the Gulf Coast, we expect lower production handling and crude transportation volumes compared to 2012, as production flowing through our Devils Tower facility declines.$16 million of income from insurance recoveries related to the abandonment of certain of Eminence storage assets in 2013;

We anticipate higher general and administrative, operating, and depreciation expense supporting our growing operations in the Marcellus Shale area.
Olefin production volumes

We expect lower ethylene volumes in 2013 as compar$9 million involuntary conversion gain recognized in 2013 related to a 2012 primarily due to major maintenance planned for 2013. With the completion of our Geismarfurnace fire for our Geismar olefins plant.
57
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
expaension in the latter part of 2013, as discussed below, we expect growth in production volumes in the fourth quarter of 2013.
Expansion projects
We expect to invest total capital
es. 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 $3.6 b1 million to $4.0 billion in 2013. The ongoing major expansion projects include the following:
Virgin
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 Southside
In December 2012, we filed an application with the FERC to expand our existing natural gas transmission system from New Jersey to a proposed power st
tatements.) 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 Virginia and a delivery poi2013 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 discont in North Carolina. The capital cost of the project is estimated to be approximately $300 million. We plan to place the project into service in September 2015, which is expected to increase capacity by 270 Mdth/d.
Mid-South
In August 2011, we received approval from the FERC to upgrade compressor facilities and expand our existing natural gas transmission system from Alabama to markets as far north as North Carolina. The cost of the project is estimated to be $200 million. We placed the first phase of the project into service in September 2012, which increased capacity by 95 Mdth/d. We plan to place the second phase of the project into service in June 2013, which is expected to increase capacity by an additional 130 Mdth/d.
Rockaway Delivery Lateral
I
ued 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 December31, 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 productio
n January 2013, we filed an application with the FERC to construct a three-mile offshore lateral to a distribution system in New York. The capitald 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 const of the project is estimated to be approximatelyruction 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 $1804 million. We plan to place the project into service during the second half of 2014, with an expected capacity of 647 Mdth/d.
Northeast Supply Link
In November 2012, we received approval from the FERC to expand our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. The cost of the project is estimated to be $390 million and is expected to increase capacity by 250 Mdth/d. We plan to place the project into service in Nov
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 December31, 2013.
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Marcellus Shale Expansion
2, compared to 73 percent at December31, 2011.
59
Year-Over-Year Operating Results Segments Williams Partner
s
Expansion of our Susquehanna Supply Hub in northeastern Pennsylvania, as previously discussed.

Expansions currently under construction to our natural gas gathering system, processing facilities and fractionator in our Ohio Valley Midstream business of the Marcellus Shale including a third turbo-expander at our Fort Beeler facility which is expected to add 200 MMcf/d of processing capacity in the first quarter of 2013. By the end of 2013, we expect our first turbo-expander at our Oak Grove facility to add 200 MMcf/d of processing capacity and additional fractionation capacity at our Moundsville fractionators bringing the NGL handling capacity to approximately 43 Mbbls/d.

Expansions to our gathering system infrastructure through capital to be invested within our Laurel Mountain equity investment, also in the Marcellus Shale region.
Gulfstar FPS Deepwater Project
We will design, construct, and install our Gulfstar FPS , a spar-based floating production system that utilizes a standard design approach with a capacity of 60 Mbbls/d of oil, up to 200 MMcf/d of natural gas, and the capability to provide seawater injection services. We expect Gulfstar FPS to be capable of serving as a central host facility for other deepwater prospects in the area. Construction is underway and the project is expected to be in service in 2014. In January 2013, WPZ agreed to sell a 49 percent ownership interest in its Gulfstar FPS project to a third party. The transaction is expected to close in second-quarter 2013, at which time we expect the third party will contribute $225 million to fund its proportionate share of the project costs, following with monthly capital contributions to fund its share of ongoing construction.
Parachute
In conjunction with a basin-wide agreement for all gathering and processing services provided by us to WPX in the Piceance basin, we plan to construct a 350 MMcf/d cryogenic natural gas processing plant. The Parachute TXP I plant is expected to be in service in 2014.
Geismar
An expansion of our Geismar olefins production facility is under way which is expected to increase the facilitys ethylene production capacity by 600million pounds per year to a new annual capacity of 1.95 billion pounds. The additional capacity will be wholly owned by us and is expected to increase our share of the Geismar production facility to over 88 percent. We expect to complete the expansion in the latter part of 2013.
Keathley Canyon Connector
Our equity investee which we operate, Discovery, plans to construct, own, and operate a new 215-mile, 20-inch deepwater lateral pipeline from a third-party floating production facility located in the Keathley Canyon production area in the central deepwater Gulf of Mexico. Discovery has signed long-term agreements with anchor customers for natural gas gathering and processing services for production from the Keathley Canyon and Green Canyon areas. The Keathley Canyon Connector lateral will originate from a third-party floating production facility in the southeast portion of the Keathley Canyon area and will connect to Discoverys existing 30-inch offshore natural gas transmission system. The lateral pipeline is estimated to have the capacity to flow more than 400 MMcf/d and will accommodate the tie-in of other deepwater prospects. Pre-construction activities have begun; the pipeline is expected to be laid in 2013 and in service in mid-2014.
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Overland Pass Pipeline Expansion
Through our equity investment in OPPL, we are participating in the construction of a pipeline connection and capacity expansions, expected to be complete in early 2013, to increase the pipelines capacity to the maximum of 255 Mbbls/d, to accommodate new volumes coming from the Bakken Shale in the Williston basin.
Eminence Storage Field leak
On December28, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Mississippi. Due to the leak and related damage to the well at an adjacent cavern, both caverns are out of service. In addition, two other caverns at the field, which were constructed at or about the same time as those caverns, have experienced operating problems, and we have determined that they should also be retired. The event has not affected the performance of our obligations under our service agreements with our customers.
In September 2011, we filed an application with the FERC seeking authorization to abandon these four caverns. In February 2013, the FERC issued an order approving the abandonment. We estimate the total abandonment costs, which will be capital in nature, will be approximately $92 million, which is expected to be spent through the end of 2013. As of December31, 2012, we have incurred approximately $69 million in cumulative abandonment costs. This estimate is subject to change as work progresses and additional information becomes known. Management considers these costs to be prudent costs incurred in the abandonment of these caverns and expects to recover these costs, net of insurance proceeds, in future rate filings. To the extent available, the abandonment costs will be funded from the ARO Trust. (See Note15 of Notes to Consolidated Financial Statements.)
Filing of rate cases
On August31, 2012, Transco filed a general rate case with the FERC for an overall increase in rates. In September 2012, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March1, 2013, subject to refund and the outcome of a hearing. We expect that our new rates, although still subject to refund until the rate case is resolved, will contribute to a modest increase in revenue in 2013. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October1, 2012 and will not be subject to refund. The impact of these specific new rates that became effective October1, 2012 is expected to reduce revenues by approximately $2 million for the period from January1, 2013 until the remaining rates that are currently suspended become effective on March1, 2013.
During the first quarter of 2012, Northwest Pipeline filed a Stipulation and Settlement Agreement with the FERC for an increase in their rates. Northwest Pipeline received FERC approval during the second quarter of 2012. The new rates, which as filed are 7.4 percent higher than the formerly applicable rates, became effective January1, 2013.
Year-Over-Year Operating Results
Years Ended December31,


Year ended December31,
2013
2012
2011
2010

(Millions)

Segment revenues
$
6,685
$
7,320
$
7,714
$
6,459

Segment costs and expenses
(5,183)
(5,619)
(5,821)

Equity earnings (losses)
104
111
142

Segment profit
$
1,606
$
1,812
$
2,035
$
1,666
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 customers 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.


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2012 vs. 2011
The decrease in segment revenues includ
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 $366million 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 $77201 million deincrease in olefin sales revenues including $42million lower ethylene production sales revenues primarily due to 10percent lower average per-unit sales prices anservice 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 $2106 million lower propylene production sales revenues primarily due to 17 percent lower averagprimarily 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 oper-unit sales prications. 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 volume.
Marketing revenues are $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 $
539 million deincrease 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 $163 million increase in fee revenues primarily due to higher volumes in the Marcellus Shale, including new volumes on our recently acquired gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses; higher volumes in the western deepwater Gulf of Mexico, including higher volumes on our Perdido Norte natural gas and oil pipelines; and higher volumes in the Piceance basin.

A $40 256million indecrease in transportation revenues associated with natural gas pipeline expansion projects placed in service during 2011 and 2012.
The decrease in segment costs and expenses of $202 million includes:
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 $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 $
137220 million decrease in costsolefin feedstock purchases due to $207 million associated with our equity NGLslower volumes, primarily due to a 31 percent decrease in average natural gas pricethe 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 $39 million decrease in system management gas costs from our gas pipeline businesses (offset in segment revenues ).

A $4651million 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 revenucosts 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 price.
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.

A
n $8150 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 William Partners segment profit includes:
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 $229 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices.

A $
13250 million increase in operating costs as previously discussedther product costs primarily due to higher system management gas costs from our gas pipeline businesses (offset in segment revenues ).
An $81 million increase in general and administrative expenses as previously discussed.
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A
n $478 million decrease in margins related to the marketing of NGLs primarily due to the impact of a significant and rapid declifavorable change in Other (income) expense - net primarily attributable to the recognition of $40 million of income associated with the net in NGL psurance recoverices, primarily during the second quarter of 2012, while product was in transit and 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 $725 million unfavorable changeaccrued loss for a settlement in wprite-downs of inventories to lower of cost or market. These unfavorable variances compare to pernciple of a producer claim against us and $23 million higher amortization of regulatory assets associated with asset retirement obligatiodns of increasing prices during 2011.in 2013. The decrease in segment profit includes:

A $31 million decrease in equity earnings 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 WPZs acquisition of additional interest in Gulfstream, which was previously reflected in Other.

A $163297 million indecrease in fee revenues as previously discussedNGL margins driven primarily by lower NGL volumes and prices and higher natural gas prices, partially offset by lower natural gas volumes.
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.

A $
4092 million indecrease in transportation revenues as previously discussed.
2011 vs. 2010
The increase in segment revenues includes:
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 $657million increase in marketing revenues primarily due to higher average NGL, crude and propylene prices. These changes are substantially offset by similar changes in marketing purchases.

A $
24450 million increase in revenues from our equity NGLs reflecting an increase of $272 million associated with a 25 percent increase in average NGL per-unit sales prices, partially offset by a decrease of $28 million associated with a 3 percent decrease in equity NGL volumesoperating costs as previously discussed.
A $167 million increase in olefin sales revenues including $126million higher ethylene production sales revenues due to 28percent higher average per-unit sales prices on 6 percent higher volumes primarily resulting from the absence of a four-week plant maintenance outage in 2010; and $30 million higher butadiene and DAC production sales revenues primarily due to higher average per-unit sales prices.

A $
107 million indecrease in fee revenuEquity earnings (losses) primarily due to higher gathering and processing fee revenues. We have fees from new volumes on our gathering assets in the Marcellus Shale in northeastern Pennsylvania, which we acquired at the end of 2010 and on our Perdido Norte gas and oil pipelines in the western deepwater Gulf of Mexico, which went into service in late 2010. In addition, higher fees in the Piceance basin are primarily a result of an agreement executed in November 2010.These increases are partially offset by a decline in gathering and transportation fees in the eastern deepwater Gulf of Mexico primarily due to natural field declines.$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.
61


A $68 million increase in transportation revenues associated with natural gas pipeline expansion projects placed in service in 2010 and 2011.
Segment costs and expenses increased $919million including:

A $
641201 million increase in marketing purchases primarily due to higher average NGL, crude and propylene prices. These changes are offset by similar changes in marketing revenuesservice revenues as previously discussed.
A $117 million increase in olefin feedstock costs including $93 million higher ethylene feedstock costs resulting from higher average per-unit feedstock costs and 6 percent higher volumes and $11 million higher butadiene and DAC feedstock costs primarily due to higher per-unit feedstock costs.
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A $
14127 million increase in operating costs reflecting $90 million higher maintenance expenses, including maintenance expenses for our gathering assets in northeastern Pennsylvania acquired at the end of 2010, more maintenance performed on our amarketing margins primarily due to favorable prices in 2013 and the absence of lossets in the western Onshore businesses, additional maintenance related to the Eminence storage leak, and higher property insurance expense. In addition, depreciation expense is $43 million higher primarily due to our new Perdido Norte pipelines and our Echo Springs expansion, both of which went into service in late 2010, along with increased depreciation of our Lybrook plant which was idled in January, 2012 when the gas was redirected to our Ignacio planrecognized in the second quarter of 2012 driven by significant declines in NGL prices while product was in transit

The absence of $30 million in gains recognized in 2010 associated with sale of certain assets in Colorados Piceance basin and involuntary conversion gains due to insurance recoveries in excess of the carrying value of certain Gulf Coast assets which were damaged by Hurricane Ike in 2008 and our Ignacio plant which was damaged by a fire in 2007.

A
n $428 million decrease in costs associated with our equity NGLs reflecting a decrease of $21 million associated with a 5 percent decrease in average natural gas prices and a $21 million decrease reflecting lower equity NGL volumes.
favorable change in Other (income) expense - net as previously discussed. 2012 vs. 2011 The indecrease in William Partners segment profitsegment revenues nlds

A $286 million higher NGL production margins reflecting favorable commodity price changes.

A $
107 366million indecrease in fee revenues as previously discussedrevenues 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 $68 million increase in transportation revenues associated with natural gas pipeline expansion projects placed in service in 2010 and 2011.

A $
5077 million indecrease in olefin product marginsales revenues including $33 42million highlower ethylene production marginssales revenues primarily due to 27 10percent higher per-unit margins on 6 percent higher volumlower average per-unit sales prices and $1926 million higher butadiene and DAC production margins primarily resulting from highlower propylene production sales revenues primarily due to 17 percent lower average per-unit marginsales prices

A $16 million increase in margins related to the marketing of NGLs, crude and propylene.

A $33 million increase in equity earnings primarily due to the acquisition of additional interest in Gulfstream and an increased ownership interest in OPPLMarketing 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 $141 million increase in operating costs as previously discussed.

A $3
09 million unfavorable change primarily related to gains recognized in 2010 as previously discussed.
Williams NGL& Petchem Services
Our Williams NGL& Petchem Services segment includes our oil sands offgas processing plant near Fort McMurray, Alberta and our NGL/olefin fractionation facility and butylene/butane (B/B) splitter facility at Redwater, Alberta. We produce NGLs and propylene. Our NGL products include: propane, normal butane, isobutane/butylene (butylene), and condensate. Prior to the operation of the B/B splitter, which was placed into service in August 2010, we also produced and sold B/B mix product which is now separated and sold as butylene and normal butane.
Significant events for 2012
Boreal Pipeline
The Boreal Pipeline, which replaced third party transportation, was completed and placed into service in June2012, requiring line fill that initially reduced volumes available for sale. The Boreal Pipeline is a 261-mile, 12-inch diameter pipeline in Canada that transports recovered NGLs and olefins from our extraction plant in Fort McMurray to our Redwater fractionation facility. The pipeline has an initial capacity of 43 Mbbls/d that can be
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increased to an ultimate capacity of 125 Mbbls/d with additional pump stations. The ultimate capacity provides sufficient capacity to transport additional recovered liquids in excess of those from our current agreements, including the anticipated ethane/ethylene mix resulting from ethane recovery projects expected to be placed into service in 2013.
Acquisition of liquids pipelines
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.
Contribution of Gulf olefins production facilities
In November 2012, we contributed to WPZ our 83.3 percent interest and operatorship of the olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf region. Prior period segment disclosures have been recast for this transaction.
Outlook for 2013
The following factors could impact our business in 2013.
Commodity margin changes
While per-unit margins are volatile and highly dependent upon continued demand within the global economy, we believe that our gross commodity margins will be comparable or increase slightly over 2012 levels. NGL products are currently the preferred feedstock for ethylene and propylene production which has been shifting away from the more expensive crude-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets because of our NGL-based olefins production.
Allocation of capital to projects
We expect to spend $390 million to $590 million in 2013 on capital projects. The major expansion projects include:
decrease in system management gas sales from our gas pipeline businesses (offset in segment costs and expenses ).

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

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

As previously discussed, we will combine our new liquids pipelines with an organic build-out of several projects to expand our petrochemical services.
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Year-Over-Year Operating Results

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.

Year ended December31,

2012
2011
2010
A $137million decrease in costs associated with our equity NGLs primarily due to a 31 percent decrease in average natural gas prices.

(Millions)

Segment revenues
$
279
$
341
$
238
A $39 million decrease in system management gas costs from our gas pipeline businesses (offset in segment revenues ).


Segment profit
$
99
$
157
$
80
A $46million 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.

2012 vs. 2011
Segment revenues decreased primarily due to:

$53A $132 million lower NGL product sales revenues primarily due to 22 percent lower average per-unit sales prices.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.
62


$12 million lower propylene product sales revenues 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 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.An $81million 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:

$12 million lower propylene product margins primarily due to 24 percent lower average per-unit margins on higher sales volumes.

The absence of $19 million of income related to the reduction of our accrual for the Gulf Liquids litigation in 2011.
2011 vs. 2010
Segment revenues increased primarily due to:
A $229 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices.

$79 million higher NGL production revenues primarily resulting from:

Higher average per-unit sales prices driven by a change in our Canadian product mix. Through mid-2010, we sold B/B mix product, but in August 2010, we began producing and selling both butylene and normal butane that was produced by our B/B splitter. The separated products receive higher values in the marketplace than the B/B mix sold previouslyA $132 million increase in operating costs as previously discussed.
Higher NGL sales prices resulting from higher market prices.

29 percent increased sales volumes on our butylene and normal butane products primarily due to lower volume impact of operational and maintenance issues in 2011 as compared to 2010An $81 million increase in general and administrative expenses as previously discussed.
$26 million higher propylene production revenues due to 30 percent higher average per-unit sales prices on 10 percent higher volumes primarily due to lower volume impact of operational and maintenance issues in 2011 as compared to 2010.
Segment costs and expenses increased $26 million primarily as a result of:

$14A $47 million higher operating and maintenance expenses primarily resulting from higher repairs and maintenance.
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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.

$14 million higher NGL feedstock costs primarily due to higher average per-unit feedstock costs on certain products and increased volumes on our butylene and normal butane products primarily due to reduced maintenance and operational issues.

$7 million higher costs relating to general and administrative expenses and asset retirementsA $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 WPZs acquisition of additional interest in Gulfstream, which was previously reflected in Other.
The absence of a $6 million favorable customer settlement in 2010.
These increases were partially offset by $19 million of income related to the reduction of our accrual for the Gulf Liquids litigation in 2011.
Segment profit increased primarily due to:

$42A $203 million higher NGL production margins on the butylene and normal butane products primarily resulting from higher average per-unit margins primarily driven by a change in product mix, higher NGL sales prices, and higher volumesincrease in fee revenues as previously discussed.
$24 million higher propylene production margins resulting from 37 percent higher per-unit margins and 10 percent higher volumes.

$23A $106 million increase in olefin product margins including $88 million higher propaethylene production margins primarily due to 378 percent higher per-unit margins and 5 percent higher volumes.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

$19 million of income related to the reduction of our accrual for the Gulf Liquids litigation in 2011.
These increases were partially offset by $14 million higher operating and maintenance expenses, $7 million higher costs relating to general and administrative expenses and asset retirements, and the absence of a $6 million favorable customer settlement in 2010.
Access Midstream Partners
Our Access Midstream Partners segment includes our equity method investment in Access Midstream Partners. As of December31, 2012, this investment includes a 24 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.
We acquired these interests in Access Midstream Partners on December20, 2012, and the equity earnings recognized for the current period are insignificant.
Outlook for 2013
In conjunction with our investment in Access Midstream Partners in December 2012, Access Midstream Partners also completed the acquisition of the substantial majority of Chesapeake Energys remaining midstream assets for approximately $2.16 billion. This acquisition significantly expanded the scale and geographic diversity of Access Midstream Partners assets, which benefit from long-term fee-based contracts and extensive acreage dedications from producers. In addition to growth opportunities involving existing customers, Access Midstream Partners believes the scale of its operations in high-growth basins provides significant growth potential through business development. As a result of the stable cash flows from its businesses and the expected contribution from its recent acquisition, Access Midstream Partners expects its annual distributions to unitholders will grow by approximately 15 percent in 2013.
Considering the expected distribution growth from Access Midstream Partners, including the benefit we receive from our 50 percent indirect interest in Access GP and its incentive distribution rights, we expect to
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recognize growing equity earnings from our investment. Our earnings recognized, however, will be somewhat reduced by the non-cash amortization of the difference between the cost of our investment and our underlying share of the net assets of Access Midstream Partners. (See Notes 1 and 2 of Notes to Consolidated Financial Statements.)
Other
Other includes other business activities that are not operating segments as well as corporate operations.
Year-Over-Year Operating Results


Yeares Ended Dcme3,
2013
2012
2011
2010

(Millions)

Segment revenues
$
273
$
279
$
341

Segment costs and expenses
(235
)
(180
)
(184
)

Segment profit
$
38

$
2599
$
24157
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) expensenet 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
63
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
$
4961
$
24
$
682013 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



YearsEndedDecember31,

2013
2012
2011


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. As part of a settlement regarding certain Venezuelan assets in the first quarter of 2012, we received payment for all outstanding balances due from the sale. (See Note 4 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.
2011 vs. 2010
The unfavorable change in s egment profit is primarily due to $32 million of decreased gains recognized in 2011 related to the 2010 sale of our interest in Accroven SRL and $21 million decreased equity earnings due to the contribution of the interest in Gulfstream in May 2011.
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Managements Discussion and Analysis of Financial Condition and Liquidity
Overview
In 2012, we continued to focus upon growth through disciplined investments. Examples of this growth included:
(Millions)

Our investment in Access Midstream Partners;Segment revenues
$
36
$
27
$
25


Williams Partners Laser and Caiman Acquisitions;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
64
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.
65
Managements 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:


Continued investment in Williams Partners gathering and processing capacity and infrastructure in the Marcellus Shale area, western United States, and deepwater Gulf of Mexico;

Expansion of Williams Partners interstate natural gas pipeline system to meet the demand of growth markets;
These investments were funded through cash flow from operations, debt and equity offerings at WMB and WPZ, and cash on hand.
Outlook
We seek to manage our businesses with a focus on applying conservative financial policy and maintaining investment-grade credit metrics. Our plan for 2013 reflects our ongoing transition to an overall business mix that is increasingly fee-based. Although our cash flows are impacted by fluctuations in energy commodity prices, that impact is somewhat mitigated by certain of our cash flow streams that are not directly impacted by short-term commodity price movements, as follows:

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

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 in our midstream businesses.
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, working capital, and tax and debt interest paymentsdebt service payments, and tax payments, including an estimated $111 million tax payment as a result of WPZs expected acquisition of certain of our Canadian operations, while maintaining a sufficient level of liquidity. In particular, we note the following for 2013:
We expect capital and investment expenditures to total between $3.975 billion and $4.575 billion in 2013. Of this total, maintenance capital expenditures, which are generally considered nondiscretionary and include expenditures to meet legal and regulatory requirements, to maintain and/or extend the operating capacity and useful lives of our assets, and to complete certain well connections, are expected to total between $355 million and $430 million. Expansion capital expenditures, which are generally more discretionary to fund projects in order to grow our business are expected to total between $3.62billion and $4.145 billion. See Results of Operations Segments, Williams Partners and Williams NGL& Petchem Services for discussions describing the general nature of these expenditures. In addition, we retain the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

We expect to pay total cash dividends of approximately $1.44 per common share,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 increase of 20 percent over 2012 levels. Wlude 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 increase our dividend quarterly through paying out substantially all of the cash distributotal 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 $3.8billion and $4.6 billion. See Company Outlook - Expansion Projects for discussions describing the general nature of these expenditures. In additions, net of applicable taxes, interest and costs, we receive from WPZwe 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 fund capital and investment expenditures, tax and debt service payments, dividends and distributions, and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, utilization of our revolvers, and Williams and WPZ debt and/or equity securities as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $2.075 billion and $2.55 billion in 2013.

We expect to maintain consolidated liquidity (which includes liquidity at WPZ) of at least $1 billion from cash and cash equivalents and unused revolver capacity.
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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 2013. Our internal and external sources of consolidated liquidity include cash generated from our operations, cash and cash equivalents on hand, and our revolvers. Additional sources of liquidity, if needed, include bank financings, proceeds from the issuance of long-term debt and equity securities, and proceeds from asset sales. These sources are available to us at the parent level and are expected to be available to certain of our subsidiaries, particularly equity and debt issuances from WPZ. WPZ is expected to be self-funding through its cash flows from operations, use of its revolver, and its access to capital markets. WPZ makes cash distributions to us in accordance with the partnership agreement, which considers our level of ownership and incentive distribution rights. As a result of our equity investment in Access Midstream Partners, we expect to receive quarterly cash distributions, based on our level of ownership and incentive distribution rights. Our ability to raise funds in the capital markets will be impacted by our financial condition, interest rates, market conditions, and industry conditions.
Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include:
pay total cash dividends of approximately $1.75 per common share in 2014, an increase of 22 percent over 2013 levels.

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

Lower than expected distributions, including incentive distribution rights, from WPZ. WPZs liquidity could also be impacted by a lack of adequate access to capital markets to fund its growth;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 WPZs 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.
66
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 WPZs offerings of common units, our credit facility and WPZs 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.


Lower than expected levels of cash flow from operations from Williams NGL& Petchem Services.


December31, 20123

Available Liquidity
Expiration
WPZ
WMB
Total

(Millions)

Cash and cash equivalents
$
1020
$
81579 (1)
$
839681

Available capacityCapacity available under our $900 m1.5 billion crevolver (2)
June3,2016
9
dit facility (expires July 31, 2018) (2)
1,5
00
91,50

Capacity available to WPZ under its $2.
45 billion revolver (3)
June 3, 2016
five-year credit facility (expires July 31, 2018) less amounts outstanding under its $2 billion commercial paper program (3)(4)
2,
0275
2,
025
275

$
2,045377
$
1,712,079 $
3,7644,456
__________



(1)
Includes $531278million of cCash and cash equivalents held primarily by certain international entities, that we intend to utilize to fund growth in our Canadian midstream operations and therefore, is not considered available for general corporate purposes. The remainder of our cCash and cash equivalents is primarily held in government-backed instruments.


(2)
We did not borrow on our credit facility during 2013. At December31, 20123, we are in compliance with the financial covenants associated with this crevolverdit facility. (See Note 123 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 WPZs commercial paper program. As of February 25, 20134, $97500 million of loans areis outstanding under this revolverWPZs commercial paper program. At December31, 20123, WPZ is in compliance with the financial covenants associated with the WPZ revolver.credit facility and commercial paper program. (See Note 13 Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.) The WPZ crevolverdit facility is only available to WPZ, Transco, and Northwest Pipeline as co-borrowers. (See Note 12 of Notes to Consolidated Financial Statements.)
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 WPZs commercial paper program in excess of the capacity available under WPZs credit facility.
In addition to the crevolversdit facilities and WPZs commercial paper program listed above, we have issued letters of credit totaling $2716 million as of December31, 20123, under certain bilateral bank agreements.
67
As described in Note 123 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 WPZs partnership agreement require it to make quarterly distributions of all available cash, as defined, to its unitholders.
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Shelf Registrations
WPZ filed a shelf registration stateme
Commercial Paper In March 2013, WPZ initiated a commercial paper program. The program allows a maximum outstanding amount ast a well-known, seasoned issuer in February 2012 to facilitate unlimited issuances of registered debt and limited partnership unit securities.
At the parent-company le
ny 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, we filed a shelf registration statement as a well-known, seasoned issuer in May2012 to facilitate unlimited issuances of registered debt and equity securities.
Debt Offerings
In December 2012, we completed a public offering of $850 million of 3.7 percent senior unsecured notes due in 2023. We used the $842 million net proceeds to finance a portion of our investment in Access Midstream Partners.
In August
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 20123, WPZ completed a public offering of $75600 million of its 3.34.5 percent senior unsecured notes due in 2022. WPZ used the $745 million net proceeds to repay outstanding borrowings under the WPZ revolver and for general partnership purposes.
In July 2012, Transco received net proceeds of $395 million from the issuance of $400 million of 4.45 percent senior unsecured notes due in 2042. These proceeds were used to repay Transcos $325 million 8.875 percent not
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 corporate purposes, including capital expenditures.
Equity Offerings
In December 2012, we issued 46.5million shares of common stock in a public offering at a price of $31.00 per share. We also sold an additional 7million shares for $31.00 per share to the underwrit
partnership purposes. Distributions from Equity Method Investees Our equity-method investees organizational documents require distribution of their available cash to their members upon the underwriters exercise of their option to purcha quarterly basis. In each case, additional common shares. The net proceeds of $1.6 billion were used to fund the consideration for a portion of our investment in Access Midstream Partners, as well as related transaction expenses.
In August
vailable 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 20123, WPZ completed an equity issuance of 8,500,000 common units representing limited partner interests at a price of $51.43 per unit. Subsequently, WPZ sold an additional 1,275,000 common units for $51.43 per unit to the underwriters upon thfiled 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 uanderwriters exercise of their option to purchase additional common units. The net proceeds of $488 million were used to repay outstanding borrowings under the WPZ revolver and for general partnership purposes.
In April 2012, we issued 30million 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
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 portion of the purchase of additional WPZ common units in connection with WPZs Caiman Acquisition.
In April
rincipals. As of December 31, 2013, no common units have been issued under this registration. Equity Offerings In August 20123, WPZ completed an equity issuance of 10,21,5000,000 common units representing limited partner interests at a price of $54.56 per unit. Subsequently, WPZ sold an additional 973,368 common units for $54.56 per unit to the underwriters upon. Subsequently, the underwriters exercise ofd their option to purchase additional3,225,000 common units. The net proceeds of $581 million were used for general partnership purposes, including the funding of a portion of the cash purchase price of the Caiman Acquisition.
In January
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 20123, WPZ completed an equity issuance of 7,0014,250,000 common units representing limited partner interests at a price of $62.81 per unit. In February 2012, WPZ sold an additional 1, including 3,0500,000 common units for $62.81 per unit to the underwriters uponsold to us in a private placement. Subsequently, the underwriters exercise ofd their option to purchase additional1,687,500 common units. The net proceeds of $490 million were used to fund capital expenditures and for general partnership purposes.
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Table of Contents
Acquisitions and Investments
In December 2012, we purchased an investment in Access Midstream Partners in exchange for approximately $2.19 billion in cash, including transaction costs.
In November 2012, WPZ completed the purchase of our 83.3 percent undivided interest and operatorship of the olefins production facility in Geismar, Louisiana, along with our refinery grade propylene splitter and pipelines in the Gulf region for total consideration of $2.364 billion. We received $25 million cash and 42,778,812 of WPZ common units. We have agreed to temporarily waive dis
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 WPZs 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
68
con
tributions otherwise due in respect of our incentive distribution rights (IDRs) of $16 million per quarter, beginning with the fourth quarter 2012f 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.
In April 2012, WPZ completed the Caiman Acquisition in exchange for aggregate consideration of $1.72 billion in cash, net of purchase price adjustments, and 11,779,296 of WPZs common units. In connection with this acquisition, we made an additional investment in WPZ of $1 billion to facilitate the acquisition. We purchased 16,360,133 WPZ common units and have agreed to temporarily waive distributions otherwise due in respect of our IDRs related to these units and the units issued to the seller of Caiman Eastern Midstream, LLC, in connection with this acquisi
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 WPZs cash distribution metrics as its large platform of growth projects moves toward completion. Cash distribution,s through 2013. The foregone IDRs would have yielded approximately $24 million in 2012.
In February 2012, WPZ completed the Laser Acquisition in exchange for $325 million in cash, net of cash acquired in the transaction, and 7,531,381 of WPZs common units.
o 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:




RatingAgency
Date of Last Change
Outlook
Senior
Unsecured
DebtRating
Corporate

rdtaig
Williams:


Standard&Poors
March5,2012
Stable
BBB-
BBB


MoodysInvestorsService
February27,2012
Stable
Baa3
N/A


Fitch Ratings
February 9, 2012
Stable
BBB-
N/A


Williams Partners:


Standard & Poors
March 5, 2012
Stable
BBB
BBB


Moodys Investors Service
February 27, 2012
Stable
Baa2
N/A


Fitch Ratings
February 9, 2012
Positive
BBB-
N/A

With respect to Standard and Poors, 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 Poors 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 Poors may modify its ratings with a + or a - sign to show the obligors relative standing within a major rating category.
With respect to Moodys, 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.
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Table of Contents
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 obligors 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 December31, 20123, we estimate that a downgrade to a rating below investment grade for us or WPZ could require us to post up to $78 million or $429282million, respectively, in additional collateral with third parties.
69
Sources (Uses) of Cash



Years Ended December31,

2013
2012
2011
2010

(Millions)

Net cash provided (used) by:

Operating activities
$
2,217
$
1,835
$
3,439
$
2,651

Financing activities
1,677
5,036
(342
)
573

Investing activities
(4,052
)
(6,921
)
(3,003
)
(4,296
)


Increase (decrease) in cash and cash equivalents
$
(158
)
$
(50
)
$
94
$
(1,072
)
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 WPZs commercial paper issuances;


$1.705 billion received from WPZs credit facility borrowings:


$994 million net proceeds received from WPZs 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 WPZs credit facility borrowings;


$1.819 billion received from WPZs 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


Operating activities
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.
Our net cash provided by operating activities in 2011 increased from 2010 primarily due to higher operating income from our continuing businesses.
Financing activities
Significant transactions include:
2012

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


$1.559 billion received from WPZs 2012 equity offerings;

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

$842 million net proceeds received from our December 2012 public offering of $850 million of 3.7 percent senior unsecured notes due 2023;
70


$745 million net proceeds received from WPZs August 2012 public offering of $750 million of senior unsecured notes due 2022;


$395 million net proceeds received from Transcos July 2012 issuance of $400 million of senior unsecured notes;

$1.49 billion received from WPZ revolver borrowings used for general partnership purposes, including capital expenditures;

$1.
11549 billion of WPZ revolver borrowings paid;
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Table of Contents
received from WPZs credit facility borrowings;


$1.115 billion of WPZs credit facility borrowings paid;


$325 million paid to retire Transcos 8.875 percent notes that matured in July 2012;


We paid $742 million of quarterly dividends on common stock for the year ended December31, 2012;

We paid $387 million of dividends and distributions to noncontrolling interests;
2011

We paid $387 million of dividends and distributions to noncontrolling interests. 2011


$526 million of cash retained by WPX upon spin-off on December31, 2011;


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


$1.5 billion received from WPXs issuance of senior unsecured notes in November 2011;


$500 million received from WPZs 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 Transcos senior unsecured notes that matured in August 2011;

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

$300 million received in borrowings from WPZs $1.75 billion unsecured credit facility;


$150 million paid to retire WPZs senior unsecured notes that matured in June 2011;


We paid $457 million of quarterly dividends on common stock for the year ended December31, 2011;

$425 million in net borrowings and payments related to WPZs revolving credit facility;

We paid $214 million of dividends and distributions to noncontrolling interests.
2010
$425 million in net borrowings and payments related to WPZs credit facility;

$369 million received from WPZs December 2010 equity offering used primarily to reduce revolver borrowings mentioned below and to fund a portion of WPZs acquisition of a midstream business in Pennsylvanias Marcellus Shale in December 2010;

$200 million received in revolver borrowings from WPZs $1.75 billion unsecured credit facility primarily used for WPZs general partnership purposes and to fund a portion of the cash consideration paid for WPZs acquisition of certain gathering and processing assets in Colorados Piceance basin in NovemberWe paid $214 million of dividends and distributions to noncontrolling interests. Investing activities Significant transactions include: 2010;3

$600 million received from WPZs public offering of 4.125 percent senior unsecured notes in November 2010 primarily used to fund a portion of the cash consideration paid to our former exploration and production business for WPZs acquisition of certain gathering and processing assets in Colorados Piceance basin;

$430 million received in revolver borrowings from WPZs $1.75 billion unsecured credit facility primarily used to fund our increased ownership in OPPL, a transaction that closed in SeptembeCapital expenditures totaled $3.572 billion for 20103;
$437 million received from a WPZ equity offering used to reduce WPZs revolver borrowings mentioned above;

$3.491 billion received by WPZ in February 2010 from the issuance of $3.5 billion of senior unsecured notes related to our 2010 strategic restructuring;Purchases of and contributions to our equity method investments of $455 million. 2012

$3 billion of senior unsecured notes retired in February 2010 and $574 million paid in associated premiums utilizing proceeds from the $3.5 billion debt issuance;
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Table of Contents

$250 million received from revolver borrowings on WPZs $1.75 billion unsecured credit facility in February 2010 to repay a term loan;Capital expenditures totaled $2.529 billion for 2012;
71


We paid $284 million of quarterly dividends on common stock for the year ended December31, 2010;

We paid $145 million of dividends and distributions to noncontrolling interests.
Investing activities
Significant transactions include:
2012
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;

Capital expenditures totaled $2.5 billion for 2012;

Purchases of and contributions to our equity method investments were $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 WPZs Caiman Acquisition in April 2012;
$1.72 billion paid, net of purchase price adjustments, for WPZs Caiman Acquisition in April 2012;

$ 35mlinpi,nto ahaqie ntetascin o PsLsrAqiiini ac 02

$121 million received from the reconsolidation of the Wilpro entities. (See Note 3 of our Notes to Consolidated Financial Statements.) This cash is only considered available for use in our international operations;
2011

Capital expenditures totaled $2.8 billion in$121 million received from the reconsolidation of the Wilpro entities (see Note 4 Discontinued Operations of our Notes to Consolidated Financial Statements). 2011;

We contributed $137 million to our Laurel Mountain equity investment.
2010

Capital expenditures totaled $2.
8796 billion in 2010. Included is approximately $599 million, including closing adjustments, related to our former exploration and production business acquisition in the Marcellus Shale in July 20101;
We paid approximately $949 million, including closing adjustments, for our former exploration and production business December 2010 business purchase, consisting primarily of oil and gas properties in the Bakken Shale;

We contributed $
488137 million to our investments, including a $424 million cash payment for WPZs September 2010 acquisition of an increased interest in OPPL;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 December31, 2013:

We paid $150 million for WPZs December 2010 business purchase, consisting primarily of certain midstream assets in the Marcellus Shale.
Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in Notes 10, 12, 16 and 17 of Notes to Consolidated Financial Statements. We do not believe these guarantees or the possible fulfillment of them will prevent us from meeting our liquidity needs.
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Table of Contents
Contractual Obligations
The table below summarizes the maturity dates of our contractual obligations at December31, 2012:


20134
201
45 -
20156
201
67 -
20178
Thereafter
Total

(Millions)

Long-term debt, including current portion:
Principal
$
$
7501,125
$
1,53285 $
8,
482980
$
1
0,7671,390

Interest
575624
1,1
823
1,0
08
4,751
7,457
26
5,008
7,840

Commercial paper
225
225


Cptllae
1
1
2

Operating leases (1)
5
1
86
62
4
91
66

1
238
33
74

Purchase obligations (2)
1,675
273
215
504
2,667
2,055
519
440
938
3,952


Other
long-term liabilitieobligations (3)(4)
12
12
1
3
4

Total
$
2,303961
$
2,234919
$
2,82017
$
1
3,8765,049
$
2
1,2333,746
__________



(1)
Includes a right-of-way agreement with the Jicarilla Apache Nation
, which is considered an operating lease. We are required to make a fixed annual payment of $7.58 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 20145 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 20134 based on 20123 gathering volumes is $7.35 million and is included in the table for year 2013.4.


(2)
Includes approximately $1.
32 billion in open property, plant and equipment purchase orders. Larger projects include Gulfstar One and the Geismar plant expansion. Also iOak Grove plant. Includes an estimated $579621 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December31, 20123 prices.This obligation is part of an overall exchange agreement whereby volumes we transport on OPPL are sold at a third-party fractionator
72
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 Results of Operations SegmenCompany 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 $
92100million in 20123 and $8392million in 20112. In 20134, we expect to contribute approximately $7100million to these plans (see Note 89 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 20123, we contributed $790 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 20134, we expect to contribute approximately $960 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
67 Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of income taxes, including our contingent tax liability reserves.
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Table of Contents
Effects of Inflation
Our operations have historically not been materially affected by inflation. Approximately 5247 percent of our gross property, plant, and equipment is comprised of our interstate natural gas pipelines. These 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 the remainder of our businesour 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 use of hedging instruments and 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 U.S. Environmental Protection Agency (EPA)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 $467 million, all of which are included in aA ccrued liabilities and oOther noncurrent liabilities on the Consolidated Balance Sheet at December31, 20123 . We will seek recovery of approximately $103 million of these accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 20123 , we paid approximately $716 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $123 million in 20134 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results
73
of studies or our experience with other similar cleanup operations. At December31, 20123 , 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 non-attainment 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 pProperty, 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 non-attainment 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 pProperty, plant and equipment - net on the Consolidated Balance Sheet for both new and existing facilities in affected areas.
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Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (NESHAP) regulations that will impact our operations. The emission control additions required to comply with the NESHAP regulations are estimated to include capital costs in the range of $11 million to $13 million through 2013, the compliance date.
In June 2010, the EPA promulgated a final rule establishing a new one-hour sulfur dioxide (SO 2 ) NAAQS. The effective date of the new SO 2 standard was August23, 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 January22, 2010, the EPA set a new one-hour nitrogen dioxide (NO 2 ) NAAQS. The effective date of the new NO 2 standard was April12, 2010. This standard is subject to challenge in federal court. On January20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO 2 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 NO 2 monitoring network beginning in 2013. However on October5, 2012, the EPA proposed a graduated implementation of the monitoring network between January1, 2014 and January1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO 2 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 NO 2 standard. Because we are unable to predict the outcome of the EPAs 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.
74
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 WPZs 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 December31, 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


Item7A.
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 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 12 of Notes to Consolidated Financial Statements.)
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The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December31, 2012 and 2011. 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.


2013
2014
2015
2016
2017
2018
Thereafter () Total
Fair Value
December 31,
20123

(Millions)

Long-term debt, including current portion: (2):

Fixed rate
$
$
$
750
$
375
$
785
$
8,449500
$
8,943

$
101,3593
$
1
2,0131,971

Interest rate
5.5
%
5.56
%
5.6
%
5.75
%
5.64
%
6.0
%

Variable rate (3)
$
225
$
$
$
375
$
$
$
37225 $
37225
Interest rate (34)

2012
2013
2014
2015
2016
2017
Thereafter () Total
Fair Value
December 31,
20112

(Millions)

Long-term debt, including current portion: (2):

Fixed rate
$
352
$
$
$
750
$
375
$
7
,24185
$
8,449

$
8,71810,359
$
102,0413
Interest rate
6.05.5
%
6.05.5
%
6.05.6
%
6.15.7
%
6.25.6
%
6.
5
%
0
%

Variable rate
$
$
$
$
375
$
$
$
375
$
375

Interest rate (4)
__________________


(1)
Includes unamortized discount and premium.


(2)
Excludes capital leases. (3) Consists of Commercial paper.

(3)
The weighted average interest rate at December31, 2012 was 2.7 percent.
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. (See Note 16 of Notes to Consolidated Financial Statements.)
We measure the risk in our portfolio using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolio. Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolio. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolio will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolio in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.
86
Table of Contents
We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value at risk separately for these two categories. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from our estimation of value at risk.
Trading
Our limited trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. At December31, 2012, we had no trading derivatives in our portfolio. The fair value of our trading derivatives at December31, 2011, was a net asset of less than $0.1 million. The value at risk for contracts held for trading purposes was zero at December31, 2012, and less than $0.1 million at December31, 2011.
Nontrading
Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from natural gas purchase and NGL purchase and sale activity. The fair value of our nontrading derivatives was a net asset of $4 million and $1 million at December31, 2012, and 2011, respectively. The value-at-risk for derivative contracts held for nontrading purposes was less than $0.1 million at December31, 2012, and zero at December31, 2011. During the year ended December31, 2012, our value at risk for these contracts ranged from a high of $2.3 million to a low of zero.
Certain of the derivative contracts held for nontrading purposes in 2012 were accounted for as cash flow hedges but realized during the year. As of December31, 2012, the energy derivative contracts in our portfolio have not been designated as cash flow hedges.
Trading Policy
We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities, and term and exposure limitations.
Foreign Currency Risk
Net assets of our consolidated foreign operations, whose functional currency is the local currency, located primarily in Canada were approximately $899 million and $779 million at December31, 2012 and 2011, respectively. These foreign operations do not have significant transactions or financial instruments denominated in currencies other than their functional currency. However, these investments do 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 $180 million at December31, 2012.
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Table of Contents

Item8.
Financial Statements and Supplementary Data
MANAGEMENTS ANNUAL REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules13a 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 matte
(4)
The weighted average interest rate was 0.42 percent and 2.7 percent at December31, 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 ou
r 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.
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 December31, 2012, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal ControlIntegrated Framework. Based on our assessment, we concluded that, as of December31, 2012, 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 Form10-K.
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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 December31, 2012, base
ned 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 non criteria established in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (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 Managements Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Companys 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 companys 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 companys 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 companys asse
derivative 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
75
December31, 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 December31, 2013 and 2012 , respectively. These investmen
ts 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 December31, 2012, 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 December31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December31, 2012, and our report dated February27, 2013, expressed an unqualified opinion thereon.
/s/ Ernst& Young LLP
Tulsa, Oklahoma
February27, 2013
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Table of Contents
Report of Independent Registered Public Accounting Firm
ve 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 December31, 2013 .
76
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 December31, 201
23 and 20112, and the related consolidated statements of operationsincome, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December31, 20123. 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 Companys 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 Companys investment in Gulfstream constituted one and two percent of the Companys assets as of each of December 31, 20123 and 2011, respectively2, and the Companys equity earnings in the net income of Gulfstream constituted fivesix, five, and seventeen percentfive percent, respectively, of the Companys income from continuing operations before income taxes for each of the three years in the period ended December 31, 20123. The Companys investment in ACMP constituted eight percent of the Companys assets as of December 31, 2013, and the Companys equity earnings in the net income of ACMP constituted nine percent of the Companys income from continuing operations before income taxes for the year ended December 31, 2013. Gulfstreams and ACMPs financial statements for the periods indicated above were audited by other auditors whose reports hasve 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 report
s of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report
s 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 December31, 20123 and 20112, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December31, 20123, 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 December31, 201
23, 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 February27 26, 20134, expressed an unqualified opinion thereon.
/s/ Ernst
& Young LLP
Tulsa, Oklahoma

February27 26, 20134
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77
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, 20123 and 20112, 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, 20123. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these 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, 20123 and 20112, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20123, in conformity with accounting principles generally accepted in the United States of America.
/s/ D
ELOITTE & TOUCHEeloitte & Touche LLP
Houston, Texas

February254, 2013
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THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
4
78
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 Partnerships 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 3,
2013
2012
2011
2010

(Millions, except per-share amounts)

Revenues:

Service revenues
$
2,939
$
2,729
$
2,532
$
2,359

Product sales
3,921
4,757
5,398
4,279


Total revenues
6,860
746 7,930
6,638


Costs and expenses:

Product costs
3,027
3,496
3,934
3,260

Operating and maintenance expenses
1,097
1,027
990
870

Depreciation and amortization expenses
815
756
661
612

Selling, general, and administrative expenses
512
571
477
504

Other (income) expensenet
34
24
1
(15
)


Total costs and expenses
5,485
5,874
6,063
5,231


Operating income (loss)
1,375
1,612
1,867
1,407


Equity earnings (losses)
134
111
155
143

Interest incurred
(611
)
(568
)
(598
)
(628
)

Interest capitalized
101
59
25
36

Other investing income net
81
77
13
45

Early debt retirement costs
(271
)
(606
)

Other income (expense)net
(2
)
11
(12
)


Income (loss) from continuing operations before income taxes
1,080
1,289
1,202
385

Provision (benefit) for income taxes
401
360
124
114


Income (loss) from continuing operations
679
929
1,078
271

Income (loss) from discontinued operations
(11
)
136
(417
)
(1,193
)


Net income (loss)
668
1,065
661
(922
)

Less: Net income attributable to noncontrolling interests
238
206
285
175


Net income (loss) attributable to The Williams Companies, Inc.
$
430
$
859
$
376
$
(1,097
)


Amounts attributable to The Williams Companies, Inc.:

Income (loss) from continuing operations
$
441
$
723
$
803
$
104

Income (loss) from discontinued operations
(11
)
136
(427
)
(1,201
)


Net income (loss)
$
430
$
859
$
376
$
(1,097
)


Basic earnings (loss) per common share:

Income (loss) from continuing operations
$
.65
$
1.17
$
1.36
$
.17

Income (loss) from discontinued operations
(.02
)
.22
(.72
)
(2.05
)


Net income (loss)
$
.63
$
1.39
$
.64
$
(1.88
)


Weighted-average shares (thousands)
682,948
619,792
588,553
584,552


Diluted earnings (loss) per common share:

Income (loss) from continuing operations
$
.64
$
1.15
$
1.34
$
.17

Income (loss) from discontinued operations
(.02
)
.22
(.71
)
(2.03
)


Net income (loss)
$
.62
$
1.37
$
.63
$
(1.86
)


Weighted-average shares (thousands)
687,185
625,486
598,175
590,699See accompanying notes.
80
The Williams Companies, Inc. Consolidated Statement of Comprehensive Income


See accompanying notes.
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Table of Contents
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)


Years Ended December 3,
(Millions)2013
2012
2011
2010

(Millions)

Net income (loss)
$
668
$
1,065
$
661
$
(922
)


Other comprehensive income (loss):


Cash flow hedging activities:

Net unrealized gain (loss) from derivative instruments, net of taxes of ($7)
, ($152) and ($1852) in 2012, and 2011, and 2010respectively
1

22
243
303

Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $7
, $124 and $13124 in 2012, and 2011, and 2010respectively
(1
)

(23
)
(190
)
(21
Foreign currency translation adjustments, net of taxes of $24 in 2013
(4
1 )


Foreign currency translation adjustments
22
(18
)
29


Pension and other postretirement benefits:

Prior service credit
(cost) 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
, $1 and $2 in 20123, 20112, and 20101
(2
)

(1
)
(2
)
(2
)

Net actuarial gain (loss) arising during the year, net of taxes of
$19($111), $819 and $2789 in 20123, 2011,2 and 20101, respectively (Note 9)
189

(30
)
(152
)
(56
)

Amortization of actuarial (gain) loss included in net periodic benefit cost, net of taxes of ($2
23), ($16),22) and ($136) in 20123, 2011,2 and 20101, respectively
38

39
27
23

Equity Securities:

Equity securities:

Unrealized gain (loss) on equity securities, net of taxes of ($2) in 2011
3

Rcasfctosit annso gi)ls nsl feut euiis e ftxso 2i 02 (3
)


Other comprehensive income (loss)
198
27
(88
)
86


Comprehensive income (loss)
866
1,092
573
(836
)

Less: Comprehensive income (loss) attributable to noncontrolling interests
238

206
285
175


Comprehensive income (loss) attributable to The Williams Companies, Inc.
$
628
$
886
$
288
$
(1,011
)
See accompanying notes.
81
The Williams Companies, Inc. Consolidated Balance Sheet


See accompanying notes.
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Table of Contents
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED BALANCE SHEET


December 3,
2013
2012
2011

(Millions, except per-share aons

ASSETS

Current assets:

Cash and cash equivalents
$
681
$
839
$
889

Accounts and notes receivable
, (net of allowance of $0 at December31, 2012 and $1 at December31, 2011)
688
637
:

Trade and other
600
620

Income tax receivable
74
68


Deferred income tax asset
27
117
52

Inventories
194
175
169

Regulatory assets
39
40

Other current assets and deferred charges
66
107
105


Total current assets
1,683
1,924
1,894


Investments
4,360
3,987
1,391

Property, plant, and equipment net
18,210
15,467
12,580

Goodwill
646
649

Other intangible
s assets
1,644

1,704
44

Regulatory assets, deferred charges, and other
599
596
593


Total assets
$
27,142
$
24,327
$
16,502


LIABILITIES AND EQUITY

Current liabilities:

Accounts payable
$
960
$
920
$
691

Accrued liabilities
797
628
631

Commercial paper
225

Long-term debt due within one year
1
353
1

Total current liabilities
1,983
1,549
1,675


Long-term debt
11,353
10,735
8,369

Deferred income taxes
3,529
2,841
2,157

Other noncurrent liabilities
1,356
1,775
1,715

Contingent liabilities and commitments (Note 17)


Equity:

Stockholders equity:

Common stock (960 million shares authorized at $1 par value; 71
68 million shares issued at December 31, 20123 and 626716 million shares issued at December 31, 2011)2)
718

716
626

Capital in excess of par value
11,599
11,134
7,920

Retained deficit
(6,248
)
(5,695
)
(5,820
Accumulated other comprehensive income (loss)
(164

)

Accumulated other comprehensive income (loss)
(362
)
(389
)

Treasury stock, at cost (35 million shares of common stock)
(1,041
)
(1,041
)


Total stockholders equity
4,864
4,752
1,296

Noncontrolling interests in consolidated subsidiaries
4,057
2,675
1,290


Total equity
8,921
7,427
2,586


Total liabilities and equity
$
27,142
$
24,327
$
16,502
See accompanying notes.
82
The Williams Companies, Inc. Consolidated Statement of Changes in Equity


See accompanying notes.
94
Table of Contents
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY


TeWlim opne,Ic,Sokodr

Common

Stock
Capitalin

Excess of
ParValue
Retained

Earnings
(
Deficit)
Accumulated

Other
Comprehensive
Income (Loss)
Treasury

Stock
Total Stockholders Equity
Noncontrolling Interests

Total
Stockholders
Equity
Noncontrolling
Interest
Total

(Millions)

Balance
, December 31, 20109
$
61820
$
7,6784
$
903(478
)

$
(
1682
)
$
(1,041
)
$
7,9906,803
$
5721,331
$
8,562

Net income (loss)
(1,097
)
(1,097
)
175
(922
)

Other comprehensive income (loss)
86
86
86

Cash dividends common stock
(Note 13)
(284
)
(284
)
(284
)

Dividends and distributions to noncontrolling interests
(145
)
(145
)

Issuance of common stock from debentures conversion (Note 13)
2
2
2

Stock-based compensation and related common stock issuances, net of tax
2
55
57
57

Sales of limited partner units of Williams Partners L.P.
806
806

Changes in Williams Partners L.P. ownership interest, net
49
49
(77
)
(28
)


Balance, December31, 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 134) (457
)
(457
)
(457
)

Dividends and distributions to noncontrolling interests
(214
)
(214
)

Issuance of common stock from debentures conversion (Note 13)
1
13
14
14

Sokbsdcmesto n eae omnsokisacs e ftx 4
104
108
108

Changes in Williams Partners L.P. ownership interests,nt 18
18
(30
)
(12
)

Distribution of WPX Energy, Inc. to stockholders (Note 34) (5,261
)
(219
)
(5,480
)
(81
)
(5,561
)

Other
1
1
2
(1
)
1


Balance, December 3,21
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 134) (742
)
(742
)
(742
)

Dividends and distributions to noncontrolling interests
(387
)
(387
)

Issuance of common stock from debentures conversion (Note 13)
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 134) 83
2,412
2,495
2,495

Reconsolidation of noncontrolling interest in Wilpro entities (Note
3)4)
65

65
65

Contributions
to Constitution Pipeline Company, LLC (Note 1)from noncontrolling interest
14
14

Other
8
8
(1
)
7

Balance December31, 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, 20123
$
7168
$
11,134599
$
(
5,6956,248
)
$
(
362164
)
$
(1,041
)
$
4,752864
$
2,6754,057
$
7,4278,921
See accompanying notes.
83
The Williams Companies, Inc. Consolidated Statement of Cash Flows


See accompanying notes.
95
Table of Contents
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS


Years Ended December 3,
2013
2012
2011
2010

(Millions)

OPERATING ACTIVITIES:

Net income (loss)
$
668
$
1,065
$
661
$
(922
)

Adjustments to reconcile to net cash provided (used) by operating activities:

Depreciation, depletion, and amortization
815
756
1,614
1,507

Provision (benefit) for deferred income taxes
424
26 (179
)
(155
)

Provision for loss on
goodwill, investments, property, n te ses 882
1,735

Net (gain) loss on dispositions of assets
28
(52
)
(1
)
(82
)

Gain on reconsolidation of Wilpro entities (Note 34) (144
)

Amortization of stock-based awards
37
36
52
48

Early debt retirement costs
271
606

Cash provided (used) by changes in current assets and liabilities:

Accounts and notes receivable
35
27
(197
)
(36
)

Inventories
(17
)
5
60
(81
)

Other current assets and deferred charges
25
29
(15
)
43

Accounts payable
(35
)
(110
)
250
(14
)

Accrued liabilities
175
51
(29
)

Other, including changes in noncurrent assets and liabilities
62
17
(10
)
31


Net cash provided (used) by operating activities
2,217
1,835
3,439
2,651

FINANCING ACTIVITIES:

FINANCING ACTIVITIES:Proceeds from (payments of) commercial paper net
224


Proceeds from long-term debt
2,699
3,486
3,172
5,129

Payments of long-term debt
(2,081
)
(1,468
)
(2,055
)
(4,305
)

Proceeds from issuance of common stock
18
2,550
49
12

Proceeds from sale of limited partner units of consolidated partnership
1,819
1,559
806

Dividends paid
(982
)
(742
)
(457
)
(284
)

Dividends and distributions paid to noncontrolling interests
(489
)
(349
)
(214
)
(145
)

Di
videndstributions paid to noncontrolloing interests on sale of Wilpro assets (Note 34) (38
)

Contributions from noncontrolling interests
467
13

Cash of WPX Energy, Inc. at spin-off
(526
)

Payments for debt issuance costs
(17
)
(50
)
(71
)

Premiums paid on early debt retirements
(254
)
(574
)

Othernet
52
2
5
(
57 )
5


Net cash provided (used) by financing activities
1,677
5,036
(342
)
573


INVESTING ACTIVITIES:

Capital expenditures (1)
(3,572
)
(2,529
)
(2,796
)
(2,788
)

Purchases of and contributions to equity method investments
(455
)
(2,651
)
(211
)
(488
)

Purchases of businesses
(6
)
(2,049
)
(41
)
(1,099
)

Proceeds from dispositions of investments
79
16
46

Cash of Wilpro entities upon reconsolidation (Note 34) 121

Othernet
(19
)
108
29
33


Net cash provided (used) by investing activities
(4,052
)
(6,921
)
(3,003
)
(4,296
)


Increase (decrease) in cash and cash equivalents
(158
)
(50
)
94
(1,072
)

Cash and cash equivalents at beginning of year
839
889
795
1,867


Cash and cash equivalents at end of year
$
681
$
839
$
889
$
795

_________


(1)Increases to property, plant, and equipment
$
(3,653
)
$
(2,755
)
$
(2,953
)
$
(2,755
)

Changes in related accounts payable and accrued liabilities
81
226
157
(33
)


Capital expenditures
$
(3,572
)
$
(2,529
)
$
(2,796
)
$
(2,788
)
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). WPZs 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. WPZs 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 December31, 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 December31, 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 December31, 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 VIEs 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.


See accompanying notes.
96
Table of Contents
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
Our operations are located principally in the United States and are organized into the Williams Partners, Williams NGL& Petchem Services, previously referred to as Midstream Canada& Olefins, 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 100 percent of Transcontinental Gas Pipe Line Company, LLC (Transco), 100 percent of Northwest Pipeline GP (Northwest Pipeline), 50 percent of Gulfstream Natural Gas System, L.L.C. (Gulfstream), and 51 percent of Constitution Pipeline Company, LLC (Constitution). WPZs 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. WPZs midstream assets also include substantial operations and investments in the Four Corners region, the Piceance basin, 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 includes a Canadian oil sands offgas processing plant located near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and butylene/butane splitter facility at Redwater, Alberta.
Access Midstream Partners consists of our fourth-quarter 2012 purchase of an indirect equity interest in Access Midstream Partners, GP, L.L.C. (Access GP) and limited partner interests in Access Midstream Partners, L.P. (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. (See Note 2).
Other includes other business activities that are not operating segments, as well as corporate operations.
Basis of Presentation
In November 2012, we contributed to WPZ our 83.3 percent undivided interest and operatorship of the olefins-production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf region for total consideration of 42,778,812 limited partner units of WPZ, $25 million in cash, and an increase in the capital account of its general partner to allow us to maintain our 2 percent general partner interest (Geismar Transaction). The operations of this business and the related assets and liabilities were previously reported in our Williams NGL& Petchem Services segment; however, they are now reported in our Williams Partners segment. Prior period segment disclosures have been recast for this transaction.
Following the Geismar Transaction, the Williams Partners segment includes operations related to the manufacture of olefin products. As a result, revenues within our Consolidated Statement of Operations are now presented as service revenues and product sales. We also revised the presentation of certain costs and operating expenses to align product costs with the presentation of our product sales. Costs and operating expenses has been separated into product costs, operating and maintenance expenses, and depreciation and amortization expenses. Selling, general and administrative expenses has also been combined with general corporate expenses, and depreciation and amortization expenses previously presented in selling, general and administrative expenses are now presented in depreciation and amortization expenses. All periods presented have been recast, along with corresponding information presented in the Notes to Consolidated Financial Statements, to reflect this change.
97
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Certain prior period amounts reported within total costs and expenses in the Consolidated Statement of Operations have been reclassified to conform to the current presentation. The effect of the correction increased operating and maintenance expenses and decreased selling, general, and administrative expenses , with no net impact on total costs and expenses , operating income (loss) or net income (loss) . The adjustments were $14million and $13million in 2011 and 2010, respectively.
Consolidated master limited partnership
During the first quarter of 2012, WPZ completed a public equity issuance of 8,050,000 common units representing limited partner interests. WPZ also issued 7,531,381 common units to the seller in connection with its acquisition of certain entities from Delphi Midstream Partners, LLC. (See Note 2). During the second quarter of 2012, WPZ completed a public equity issuance of 10,973,368 common units representing limited partner interests. WPZ also issued 11,779,296 common units to the seller in connection with its acquisition of Caiman Eastern Midstream, LLC (See Note 2). In connection with the closing of this acquisition, we purchased 16,360,133 additional WPZ common units. In August 2012, WPZ completed a public equity issuance of 9,775,000 common units representing limited partner interests. Following these transactions, including the previously discussed limited partner units issued in the November 2012 Geismar Transaction, we own approximately 70 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 December31, 2012.
The previously described equity issuances by WPZ had the combined net impact of increasing our noncontrolling interests in consolidated subsidiaries by $1.488 billion, capital in excess of par value by $699 million and deferred income taxes by $416 million in the Consolidated Balance Sheet.
WPZ is self-funding and maintains separate lines of bank credit and cash management accounts. Cash distributions from WPZ to us, including any associated with our incentive distribution rights, occur through the normal partnership distributions from WPZ to all partners.
Variable interest entities (VIEs)
We consolidate the activities of VIEs of which we are the primary beneficiary. The primary beneficiary of a VIE is the entity that has both the power to direct the activities of the VIE that most significantly impact the VIEs economic performance and the obligation to absorb losses or the right to receive benefits that could be significant to the VIE. As of December31, 2012, WPZ has the following consolidated VIEs:
Notes to Consolidated Financial Statements (Continued)

Gulfstar One (Gulfstar) is a consolidated wholly-owned subsidiary that, due to certain risk sharing provisions in its customer contracts, is a VIE. WPZ, as construction agent for Gulfstar, will design, construct, and install a proprietary floaUse of estimates The preparation of financial statements in conformity with accounting- production system, Gulfstar FPS, and associated pipelines which will initially provide production handling and gathering services for the Tubular Bells oil and gas discovery in the eastern deepwater Gulf of Mexico. Construction iinciples generally accepted in the United States requires management to make estimates uanderway and the project is expected to be in service in 2014. WPZ, in combination with certain advance payments from the producer customers, is currently financing the asset construction. Gulfstar has construction work in process of $532 million and $103 million included in property, plant, and equipment net as of December31, 2012 and 2011, respectively, $109 million and $101 million of deferred revenue associated with customer advance payments included in other noncurrent liabilities as of December31, 2012 and 2011, respectively, and $124 million and $33 million of accounts payable as of December 31, 2012 and 2011, respectively in the Consolidated Balance Sheet. We are committed to the producer customers to construct this system, and we currently estimate the remaining construction cost to be less than $475 million. If the producer customers do not develop the offshore oil assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Significant estimates and gas fields to be
98
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
sumptions include:

connected to Gulfstar, they will be responsible for the firm price of building the facilities. In January 2013, WPZ agreed to sell a 49 percent ownership interest in its Gulfstar FPS project to a third party. The transaction is expected to close in second-quarter 2013, at which time we expect the third party will contribute $225 million to fund its proportionate share of the project costs, following with monthly contributions to fund its share of ongoing construction.

WPZ owns a 51 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 over the decisions that most significantly impact Constitutions economic performance. WPZ, as construction agent for Constitution, will build a pipeline connecting our gathering system in Susquehanna County, Pennsylvania to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. WPZ plans to place the project in service in March 2015 and estimates the total cost of the project to be approximately $680 million, which will be funded with capital contributions from us, along with the other equity partners, proportional to ownership interest. As of December31, 2012, the Consolidated Balance Sheet includes $8 million of cash and cash equivalents , $24 million of Constitution construction work in progress representing costs incurred to date, included in property, plant and equipment net and $4 million of accounts payable .
WPZ has also identified certain interests in VIEs where it is not the primary beneficiary. These include WPZs investments in Laurel Mountain Midstream, LLC (Laurel Mountain) and Discovery Producer Services LLC (Discovery). These entities are considered to be VIEs generally due to contractual provisions that transfer certain risks to customers. As certain significant decisions in the management of these entities 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 our investments. (See Note 4).
Discontinued operations
On December31, 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 Operations reflects the results of operations of our former exploration and production business as discontinued operations.The Consolidated Statement of Comprehensive Income (Loss) for 2011 and 2010 and the Consolidated Statement of Cash Flows for 2011 and 2010 includes the results of our former exploration and production business. (See Note3.)
Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.
Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of our corporate parent and our majority-owned and controlled subsidiaries and investments. We apply the equity method of accounting for investments in unconsolidated companies in which we and our subsidiaries own 20 to 50 percent of the voting interest and exercise significant influence over operating and financial policies of the company, or where majority ownership does not provide us with control due to significant participatory rights of other owners.
99
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 Operations includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.
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;

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

Litigation-related contingencies;

Environmental remediation obligations;

Environmental remediation obligations;


Realization of deferred income tax assets;

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

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 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 businesses that are regulated can differ from the accounting requirements for nonregulated businesses. 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. We have regulatory assets of $405 million and $411 million at December31, 2012 and 2011, respectively and regulatory liabilities of $265 million and $206 million at December31, 2012 and 2011, respectively in the Consolidated Balance Sheet.
Cash and cash equivalents
Cash and cash equivalents 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.
100
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 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 10.)
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) or other income (expense) net below operating income (loss) .
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 an asset and a liability equal to 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. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. As regulated entities, Northwest Pipeline and Transco record the ARO asset depreciation offset 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 , 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 represents the excess cost over fair value of the assets of businesses acquired. It is not subject to amortization but is evaluated annually as of October1 for impairment or more frequently if impairment
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
indicators are present. Our evaluation includes an assessment of events or circumstances to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount. If so, we further compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess. We have goodwill of $649 million at December31, 2012 in the Consolidated Balance Sheet attributable to our Williams Partners segment.
Other Intangible Assets
Our identifiable intangible assets are primarily related to gas gathering, processing and fractionation contracts and relationships with customers. We have other intangibles of $1.704 billion and $44 million at December31, 2012 and 2011, respectively in the Consolidated Balance Sheet primarily attributable to our Williams Partners segment. Our intangible assets are amortized on a straight-line basis over estimated useful lives. 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 managements judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our managements 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 managements 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 managements estimate of undiscounted future cash flows and an assets or investments fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
Cash flows from revolving credit facilities
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.
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. Gains and losses on the subsequent reissuance of shares are credited or charged to capital in excess of par value 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 . 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.
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

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
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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) expensenet 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 October1 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
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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 managements judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our managements 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 managements 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 managements estimate of undiscounted future cash flows and an assets or investments 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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The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

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:



Drvtv ramn
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 pProduct sales or pProduct costs in 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 aAccumulated 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 derivatives change in fair value is recognized currently in pProduct sales or pProduct 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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The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

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 pProduct sales or pProduct 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 sales or product costs.
Certain gains and losses on derivative instruments included in the Consolidated Statement of Operations 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:
Product sales or Product costs in 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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The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

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 upgraders 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 plans 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 Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

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 managements 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 February17, 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 WPZs 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 April27, 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 WPZs 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
93



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)


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; 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:

The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges.
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.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
Oil gathering and transportation revenues and offshore production handling fees of our midstream operations 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 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 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 feed-stock and we recognize revenues when the olefins are sold and delivered.
Our midstream Canada business has processing and fractionation operations where we retain certain NGLs and olefins from an upgraders 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 three 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) . 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 14.)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Income taxes
We include the operations of our domestic corporate subsidiaries and income from our domestic subsidiary partnerships in our consolidated tax return. 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 managements 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 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 includes any dilutive effect of stock options, nonvested restricted stock units and, for applicable periods presented, convertible debt, unless otherwise noted.
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 operations 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 Operations.
Note 2. Acquisitions
Business Combinations
On February17, 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 WPZs common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entities primarily own the Laser Gathering System, which is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as 10 miles of gathering lines in southern New York.
On April27, 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, subject to the final purchase price adjustment, 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 WPZs common units on the acquisition date, adjusted to reflect certain time-based restrictions on resale. The acquired entity operates a gathering and processing business in northern West Virginia, southwestern Pennsylvania and eastern Ohio. Acquisition transaction costs of $16 million were incurred related to the Caiman Acquisition and are reported in selling, general and administrative expenses at Williams Partners in the Consolidated Statement of Operations.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
These acquisitions were accounted for as business combinations which, among other things, require assets acquired and liabilities assumed to be measured at their acquisition-date fair values. The excess of cost over those fair values was recorded as goodwill and allocated to our midstream businesses (the reporting unit) within the Williams Partners segment. Goodwill recognized in the acquisitions relates primarily to enhancing our strategic platform for expansion in the Marcellus and Utica shale plays in the Appalachian basin area. Substantially all of the goodwill is expected to be deductible for tax purposes. The amount recorded for goodwill in the Caiman Acquisition is preliminary pending final determination of the purchase price adjustment.
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, n qimn
158
656

Intangible assets:

Customer contracts
316
1,141

Customer relationships
250

Other intangible assets
2
2

Current liabilities
(21
)
(94
)

Noncurrent liabilities
(3
)


Identifiable net assets acquired
476
1,968

Goodwill
290
35
96

$
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 January1, 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 WPZs 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.
94



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

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 December20, 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 ACMPs 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 .
95



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

Note 3 Variable Interest Entities Consolidated VIEs As of December31, 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 Constitutions economic performance. WPZ, as construction agent for Constitution, is building a pipeline connecting our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. WPZ plans to place the project in service in late 2015 to 2016 and estimates the total remaining construction costs of the project to be less than $600 million , which will be funded with capital contributions from WPZ and the other equity partners, proportional to ownership interest. 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
96



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

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
$
766122
$
2,3278
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 WPZs 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 million at December31, 2013 . Caiman II WPZs 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
97



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

economic performance. At December31, 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 WPZs 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 December31, 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 December31, 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.
98



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)


Identifiable intangible assets recognized in the Laser and Caiman Acquisitions are primarily related to gas gathering, processing and fractionation contracts and relationships with customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired customer contracts and relationships, which are offset with appropriate charges for the use of contributory assets and discounted using a risk-adjusted discount rate. Those intangible assets are being amortized on a straight-line basis over an initial 30-year period which represents a portion of the term over which the customer contracts and relationships are expected to contribute to our cash flows.
We expense costs incurred to renew or extend the terms of our gas gathering, processing and fractionation contracts with customers. Approximately 70 percent and 36 percent of the expected future revenues from the customer contracts associated with the Laser and Caiman Acquisitions, respectively, are impacted by our ability and intent to renew or renegotiate existing customer contracts. Based on the estimated future revenues during the current contract periods, the weighted-average periods prior to the next renewal or extension of the existing customer contracts associated with the Laser and Caiman Acquisitions are approximately 9 years and 18 years, respectively.
Revenues and earnings related to the Laser and Caiman Acquisitions included within the Consolidated Statement of Operations since the respective acquisition dates are not material. Supplemental pro forma revenue and earnings reflecting these acquisitions as if they had occurred as of January1, 2011, are not materially different from the information presented in our accompanying Consolidated Statement of Operations (since the historical operations of these acquisitions were insignificant relative to our historical operations) and are, therefore, not presented.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Amortization of Other Intangible Assets
Amortization expense related to other intangibles was $43 million, $2 million and zero in 2012, 2011, and 2010, respectively. Accumulated amortization related to other intangibles was $45 million and $2 million at December31, 2012 and 2011, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $58 million.
Purchase of Investment
On December20, 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 now 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. In addition, we hold approximately 24 percent of ACMPs outstanding limited partnership units, for a combined ownership interest of approximately 25 percent of ACMP. 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 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 a weighted-average period of approximately 18 years.
Our investment in Access Midstream Partners is disclosed as a separate reportable segment. See Note 18 for the segment disclosures.
Note 3. Discontinued Operations
On December31, 2011, we completed the tax-free spin-off of our 100 percent interest in WPX to our stockholders. (See Note 1.) At December31, 2011, the net assets of our former exploration and production business were eliminated from our consolidated balance sheet as the spin-off was complete.
The following summarized results of discontinued operations for 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 and 2010 reflect the results of operations of our former exploration and production business as discontinued operations.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Summarized Results of Discontinued Operations


Years Ended December31,

Years Ended December 31,

2013
2012
2011
2010

(Millions)

Revenues
$
$
$
3,997

Income (loss) from discontinued operations before gain on reconsolidation, impairments, and income taxes
$
4,042


Income (loss) from discontinued operations before gain on reconsolidation, impairments and income taxes
(15
)

$
(16
)
$
223
$
350

Gi nrcnoiain 144

Impairments
(755
)
(1,682
)

(Provision) benefit for income taxes
4
8
115
139


Income (loss) from discontinued operations
$
(11
)
$
136
$
(417
)
$
(1,193
)


Income (loss) from discontinued operations:

Attributable to noncontrolling interests
$
$
$
10
$
8

Attributable to The Williams Companies, Inc.
$
(11
)
$
136
$
(427
)

$
(1,201
)
Revenues and iIncome (loss) from discontinued operations before gain on reconsolidation, impairments, and income taxes for 2011 and 2010 primarily reflects 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 the first quarter of 2012, the El Furrial and PIGAP II assets were sold as part of a settlement related to the 2009 expropriation of these assets.Upon closing, the lenders that had provided financing for these operations were repaid in full, and the Wilpro entities received $98 million in cash and the right to receive quarterly cash installments of $15 million (receivable) plus interest through the first quarter of 2016 plus interest. Following the settlement and repayment in full of the lenders, we reestablished control and, therefore, reconsolidated the Wilpro entities and recognized athe gain on reconsolidation of $144 million. This gain reflectsed our share of the cash, including cash received in the settlement, and athe estimated fair value of the receivable held by the Wilpro entities at the time of reconsolidation.The receivable was recognized at its estimated f (See Note 16 Fair vValue, as further described below.
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. See Note 15 for a further discussion of this receivable.
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
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
Impairments in 2010 include a $1,003 million impairment of domestic goodwill (to an implied fair value of zero at the assessment date) and $678 million of impairments of capitalized costs of certain natural gas producing properties in the Barnett Shale and acquired unproved reserves in the Piceance basin of our discontinued exploration and production business (to their estimated fair value of $320 million at the assessment date). These nonrecurring fair value measurements fell within Level 3 of the fair value hierarchy.
For the goodwill evaluation, we used an income approach (discounted cash flow) for valuing reserves. The significant inputs into the valuation of proved and unproved reserves included estimated reserve quantities, forward natural gas prices, anticipated drilling and operating costs, anticipated production curves, income taxes, and appropriate discount rates.
99



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

For our assessment of the carrying value of our natural gas producing properties
and costs of acquired unproved reserves, we utilized estimates of future cash flows, in certain cases including purchase offers received. Significant judgments and assumptions in these assessments are similar to those used in the goodwill evaluation and 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 December30, 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 December30, 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 December30, 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 theirits 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
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 December31, 2011.
100



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 eEnded
eebr121
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
prtos
Not designated as cash flow hedges:

Not designated as cash flow hedges

Gain (loss) recognized in income
$
30
Income
(loss) from
discontinued
operations
Note
4.5 Investing Activities
Investing Income



YearsEndedDecember31,

2013
2012
2011
2010

(Millions)

Equity earnings (losses) (1)
$
134
$
111
$
155
$
143

Income (loss) from investments (1)
28
49
7
43

Impairment of cost-based investments
(1
)

Interest income and other
53
28
7
2
6

Total investing income
$
215
$
188
$
168
$
188
__________


(1)
Items also included in
sSegment profit (loss) . (See Note 18.)
In June
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, Petrleos de Venezuela S.A. (PDVSA) for $107 million. Income (loss) from investments in 2012, 2011, and 20101 includes gains of $53 million, $11 million, and $4311 million , respectively, from the sale. As part of the settlement regarding certain Venezuelan assets in the first quarter of 2012 (see Note 3), we also received payment for all outstanding balances due from this sale, including interest. Payments were recognized upon receipt, as future collections were not reasonably assured.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Payments were recognized upon receipt, as future collections were not reasonably assured.
101



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



December31,

2013
2012
2011

(Millions)

Equity method:

Access Midstream Partners 2
5%4%
$
2,161

$
2,187
$

Overland Pass Pipeline Company LLC (OPPL) 50%
452
454
433

Gulfstream 50%
333
348
362

Laurel Mountain Midstream, LLC (Discovery Producer Services LLC (Discovery) 60% (1)
527
350

Laurel Mountain) 51% (1)
481
444
291

Discovery Producer Services LLC (Discovery) 60% (1)
350
182
Caiman II 47.5%
256
67


Other
204
122
150
137

$
4,360
$
3,987
_________



3,987
1,390
(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 December31, 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 December31, 2013 , our proportionate share of amounts remaining to be spent for specific capital projects already in
102


Cost method
1

Marketable equity securities
24

The Williams Companies, Inc.

$
3,987
$
1,415
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:

(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.
Marketable equity securities are classified as available-for-sale and included in other current assets and deferred charges in the Consolidated Balance Sheet. The carrying value is reported at fair value with net unrealized appreciation reported as a component of other comprehensive income.
Related party transactions
We have purchases from our equity method investees included in product costs in the Consolidated Statement of Operations of $186 million, $234 million, and $220 million for the years ended 2012, 2011, and 2010, respectively. We have $15 million and $23 million included in accounts payable in the Consolidated Balance Sheet with our equity method investees at December31, 2012 and 2011, 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 Operations are $75 million, $57 million and $38 million for the years ended 2012, 2011, and 2010, respectively.
Equity method investments
In addition to the discussion of the basis difference related to Access Midstream Partners in Note 2, we also have differences between the carrying value of our equity investments and the underlying equity in the net assets of the investees of $59 million at December31, 2012, primarily related to impairments we previously recognized. These differences are amortized over the expected remaining life of the investees underlying assets.
Our equity-method investees organizational documents generally require distribution of available cash to equity holders on a quarterly basis. We generally fund our portion of significant expansion or development
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
projects of these investees, except for Access Midstream Partners which is expected to be self-funding, through additional capital contributions. As of December 31, 2012, our proportionate share of amounts remaining to be spent for specific capital projects already in progress for Discovery and Laurel Mountain totaled $189 million and $55 million, respectively.
In December 2012, we completed the acquisition of a 25 percent ownership interest of Access Midstream Partners for approximately $2.19 billion in cash. (See Note 2.) We contributed $169 million to Discovery in 2012 and $174 million, $137 million and $43 million to Laurel Mountain in 2012, 2011 and 2010, respectively. In addition, in September 2010, we purchased an additional 49 percent ownership interest in OPPL for $424 million.
Dividends and distributions, including those presented below, received from companies accounted for by the equity method were $173 million, $193 million, and $175 million in 2012, 2011, and 2010, respectively. These transactions reduced the carrying value of our investments. These dividends and distributions primarily included:


2013
2012
2011
2010

(Millions)

Access Midstream Partners
$
93
$
$

Gulfstream
$81
79
$
84
$
81

Discovery
12
21
40
44

Aux Sable Liquid Products L.P.
20
28
35
28

OPPL
27
28
19
Summarized Financial Position and Results of Operations of All Equity -Method Investments



December31,

2013
2012
2011

(Millions)

Assets (liabilities):

Current assets
$
689
$
582
$
381

Noncurrent assets
13,621
11,571
8,004

Current liabilities
(573
)
(
507
378)

Noncurrent liabilities
3,807
2,324
(4,563
)
(3,807
)

Noncontrolling interest
(254
)
(112
)



Years Ended December 31,

2013
2012
2011
2010

(Millions)

Gross revenue
$
2,406
$
1,821
$
1,808
$
1,545

Operating income
699
557
747
732

Net income
627
488
654
624
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
103



The Williams Companies, Inc.

Notes to Consolidated Financial Statements
(Continued)

Note 5. Asset Sales and Other Accruals
6 Other Income and Expenses The following table presents significant gains or losses reflected in oOther (income) expense net within cCosts and expenses :



YasneDcme3,
2013
2012
2011
2010

(Millions)

Williams Partners

Project feasibility costsNet insurance recoveries associated with the Geismar Incident
$
21(40
)

$
10
$
8

CapitalAmortization of project feasibility costs previously expensed
(19
)
(11
)
(1
)
regulatory assets associated with asset retirement obligations
30
7
6

Write-off of the Eminence abandonment regulatory asset not recoverable through rates
12


Gains on sales of certain assets
(6
)
(12
Insurance recoveries associated with the Eminence abandonment
(16

)

Involuntary conversion gains
(3
)
(18
)
Settlement in principle of a producer claim
25


Accrual of regulatory liability related to overcollection of certain employee expenseProject feasibility costs 4
921
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
)
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.
Additional Items
We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December28, 2010.We recorded $2 million, $15 million, and $5 million of charges to operating and maintenance expenses at Williams Partners during 2012, 2011, and 2010, 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 .
We completed a strategic restructuring transaction in the first quarter of 2010 that involved significant debt issuances, retirements, and amendments. During 2010, we incurred $45 million of related transaction costs reflected in selling, general, and administrative expenses, of which $7 million is attributable to noncontrolling interests.
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.)
In conjunction with the completion of a tender offer for a portion of our debt in the fourth quarter of 2011 and the 2010 strategic restructuring previously discussed, we incurred $271 million and $606 million, respectively, of early debt retirement costs , consisting primarily of cash premiums.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note6.Provision (Benefit) for Income Taxes
The provision (benefit) for income taxes from continuing operations includes:

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 June13, 2013, an explosion and fire occurred at WPZs 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 December31, 2013, we have recognized $50 million of insurance recoveries related to this incident as a gain to Other (income) expensenet 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
104



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

offset the $50 million gain included in Other (income) expensenet 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 December28, 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 3,
2013
2012
2011
2010

(Millions)

Current:

Federal
$
(17
)
$
91
$
181
$
(21
)

State
7
17
13
(2
)

Foreign
(13
)
40
(6
)
29

(23
)

148
188
6


Deferred:

Federal
348
220
(61
)
144

State
40
(13
)
(14
)
(48
)

Foreign
36
5
11
12

424
212
(64
)
108


Total provision (benefit)
$
401
$
360
$
124
$
114
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:


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:


YasEddDcme3,
2013
2012
2011
2010

(Millions)

Provision (benefit) at statutory rate
$
378
$
451
$
421
$
135

Increases (decreases) in taxes resulting from:

Impact of nontaxable noncontrolling interests
(78
)
(72
)
(96
)
(58
)

State income taxes (net of federal benefit)
26
2
11
(35
)

Foreign operations net
(32
)
(36
)
(14
)
(22
)

Federal settlements
(109
)

International revised assessments
(38
)

Taxes on undistributed earnings of
certain foreign operationsforeign subsidiaries - net
99

(66
)
66

Reduction of tax benefits on Medicare Part D federal subsidy
11

Other net
8
15
15
17


Provision (benefit) for income taxes
$
401
$
360
$
124
$
114
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)


State income taxes (net of federal benefit) were reduced by $43million in 2010 due to a reduction in our estimate of the effective deferred state rate, including state income tax carryovers, reflective of a change in the mix of jurisdictional attribution of taxable income.
Income (loss) from continuing operations before income taxes includes $196million, $173million, and $144million of foreign income in 2012, 2011, and 2010, respectively.
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
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
Significant components of deferred tax liabilities and deferred tax assets are as follows:


December31,

December31,

2013
2012
2011

(Millions)

Deferred tax liabilities:

Property, plant, and equipment
$
102
$
72
$
65

Undistributed earnings of foreign subsidiaries
75

Investments
3,663
3,146
2,560

Other
34
46


Total deferred tax liabilities
3,840
3,252
2,671


Deferred tax assets:

Accrued liabilities
126
313
324

MinimumFederal tax credits *
108

74
119

State loss
es and credit carryoverss
194

195
170

Other
91
90
98


Total deferred tax assets
519
672
711


Less valuation allowance
181
144
145


Net deferred tax assets
338
528
566


Overall net deferred tax liabilities
$
3,502
$
2,724
$
2,105
The valuation allowance at December31, 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 December31, 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:


*
In conjunction with the 2011 spin-off of WPX, alternative minimum tax credits were allocated between us and WPX. In 2012, adjustments of $15 million were made to this component of the deferred tax asset for the 2009 to 2010 Internal Revenue Service (IRS) audit adjustments and finalization of the 2011 income tax return, reducing the alternative minimum tax credit allocated to WPX.
The valuation allowance at December31, 2012 and 2011 serves to reduce the available deferred tax assets associated with state loss and credit carryovers 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 loss and credit carryovers 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. 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.
In the fourth quarter of 2010, we provided $66 million of deferred taxes on the undistributed earnings of certain foreign operations that we no longer could assert were permanently reinvested due to alternatives being considered related to an existing structure impacted by the potential timing of our plan approved by our Board of Directors to pursue the separation of our exploration and production business through an IPO and subsequent tax-free spin-off.During the third quarter of 2011, associated with a ruling received from the IRS related to this separation plan, and following a certain internal reorganization, we recognized a deferred tax benefit of $66million as we considered the undistributed earnings of these certain foreign operations to be permanently reinvested. As of December31, 2012, we consider $630 million of undistributed earnings from foreign subsidiaries to be permanently reinvested and have not provided deferred income taxes on that amount.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Cash payments for income taxes (net of refunds and including discontinued operations) were $198 million, $296million, and $40million in 2012, 2011, and 2010, respectively.
As of December31, 2012, we had approximately $58million of unrecognized tax benefits. If recognized, income tax expense would be reduced by $62million, 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
2011

(Millions)

Balance at beginning of period
$
58
$
38
$
91

Additions based on tax positions related to the current year
4
264

Additions for tax positions of prior years
18
22
4

Reductions for tax positions of prior years
(2
)
(6
)
(39
)

Settlement with taxing authorities
(4412
)


Balance at end of period
$
66
$
58
$
38
107



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 December31, 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 IRSs 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 January1, 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 December31, 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.
108



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

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


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 benefits of $7 million and $56million for 2012 and 2011, respectively, and expense of $11million for 2010. Approximately $7million and $15million of interest and penalties primarily relating to uncertain tax positions have been accrued as of December31, 2012 and 2011, 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 year-to-date 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 third quarter of 2012, we reached a tentative agreement subject to government approval with the IRS on tax matters related to the IRSs examination of our 2009 and 2010 consolidated corporate income tax returns.These matters resulted in a tax provision of approximately $2 million recorded during the third quarter of 2012.With respect to the examined years, we anticipate making approximately $12 million of cash payments to the IRS in the first quarter of 2013. The 2011 tax return is 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 from 2007 through 2012, subject in the case of Venezuela to certain contractual limitations. An audit of one of our Canadian entities was concluded for the years 2007 through 2010 and we are awaiting a notice of reassessment based on a negotiated settlement. The impact of this reassessment is not expected to be material.
On December23, 2011, the IRS issued temporary regulations providing guidance on the treatment of amounts paid to acquire, produce or improve tangible property and of dispositions of such property. In fourth quarter 2012, the IRS provided notice that the implementation date for these regulations has been delayed until January1, 2014, and that additional, substantive changes to the initially issued temporary regulations would be
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Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
forthcoming, likely in 2013. 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 changes will impact 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. Pending the issuance of additional procedural guidance from the IRS and progress of the evaluation process, we cannot estimate the impact of implementing the temporary regulations.
With the spin-off of WPX on December31, 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 for purposes of any 2011 tax return. We expect that we will reimburse WPX approximately $2 million in the first quarter of 2013 for the additional losses shown on the pro forma tax returns, offset with additional tax resulting from the tentative 2009 to 2010 IRS settlement agreement.
Note 7. Earnings (Loss) Per Common Share from Continuing Operations


Years Ended December 3,
2013
2012
2011
2010

(Dollars in millions, except per-share
mut;sae ntosns


Income (loss) from continuing operations attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share
(1)
$
441

$
723
$
803
$
104


Basic weighted-average shares
682,948
619,792
588,553
584,552

Effect of dilutive securities:

Nonvested restricted stock units
1,995
2,694
4,332
3,190

Stock options
2,149
2,608
3,374
2,957

Convertible debentures
93
392
1,916


Diluted weighted-average shares
687,185
625,486
598,175
590,699


Earnings (loss) per common share from continuing operations:

Basic
$
.65
$
1.17
$
1.36
$
.17


Diluted
$
.64
$
1.15
$
1.34
$
.17
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 December31, 1991, are not eligible for the subsidized retiree medical benefits, except for participants that were employees or retirees of Transco Energy Company on December31, 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.
109



(1)
2011 includes $.7 million of interest expense, net of tax, associated with our convertible debentures. (See Note13.) This amount has been added back to income (loss) from continuing operations attributable to The Williams Companies, Inc. available to common stockholders to calculate diluted earnings per common share.
118
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
For 2010, 2.2million weighted-average shares related to the assumed conversion of our convertible debentures, as well as the related interest, net of tax, have been excluded from the computation of diluted earnings per common share. Inclusion of these shares would have an antidilutive effect on the diluted earnings per common share. We estimate that if 2010 income (loss) from continuing operations attributable to The Williams Companies, Inc. available to common stockholders was $222 million of income, then these shares would become dilutive.
Effective January1, 2012, new awards of time-based restricted stock units contain a nonforfeitable right to dividends during the vesting period. These share-based payment awards are participating securities and are included in the computation of earnings (loss) per common share pursuant to the two-class method. The impact for the year ended December31, 2012, is immaterial.
The table below includes information related to stock options for each period that were excluded from the computation of weighted-average stock options due to the option exercise price exceeding the fourth quarter weighted-average market price of our common shares. All stock options outstanding at December31, 2012 were dilutive.

The Williams Companies, Inc.

2012
2011
2010
Notes to Consolidated Financial Statements (Continued)

Options excluded (millions)
0.9
2.4
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.

Weighted-average exercise price of options excluded
$0.00
$29.68
$32.41

Exercise price ranges of options excluded
$
0.00-$0.00
$
26.10-$29.72
$
22.68-$40.51

Fourth quarter weighted-average market price
$33.38
$24.51
$22.47
Note 8. 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 December31, 1991, are not eligible for the subsidized retiree medical benefits, except for participants that were employees or retirees of Transco Energy Company on December31, 1995, and other miscellaneous defined participant groups. 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.
119
Table of Contents
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. The spin-off on December31, 2011, of WPX did not have a significant impact on our pension and other postretirement benefit plans. (See Note 3). Generally, our pension and other postretirement benefit plans have retained the benefit obligations associated with vested benefits earned by eligible employees that transferred to WPX due to the spin-off. No plan assets transferred to WPX.


Pension Benefits
Other
Postretirement
eeis
2013
2012
20113
2012
2011

(Millions)

Change in benefit obligation:

Benefit obligation at beginning of year
$
1,549
$
1,441
$
1,267331
$
339
$
289

Service cost
44
39
412
3
2

Interest cost
51
55
6411
13
15

Plan participants contributions
6
5
6

Benefits paid
(87
)
(75
)
(6619
)
(20
)
(22
)

Medicare Part D
and Early Retiree Reinsurance Program subsidiessubsidy
4

3
4

Plan amendment
(59
)
(6
)
(3
)

Actuarial loss (gain)
(173
)
98
143(63
)

(6
)
48

Settlements
(9
)
(8
)


Benefit obligation at end of year
1,384
1,549
1,441213
331
339


Change in plan assets:

Fair value of plan assets at beginning of year
1,071
965
971175
159
162

Actual return on plan assets
165
111
31
18
(2
)

Employer contributions
92
79
68 13
15

Plan participants contributions
6
5
6

Benefits paid
(87
)
(75
)
(6619
)
(20
)
(22
)

Settlements
(9
)
(8
)


Fair value of plan assets at end of year
1,241
1,071
965201
175
159


Funded status underfunded
$
(143
)
$
(478
)
$
(47612
)
$
(156
)
$
(180
)


Accumulated benefit obligation
$
1,359
$
1,519
$
1,415
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:

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:


Dcme3,
2013
2012
2011

(Millions)

Underfunded pension plans:

Current liabilities
$
1
$
3
$
7

Noncurrent liabilities
142
475
469

Underfunded other postretirement benefit plans:

Current liabilities
8
8

Noncurrent liabilities
4
148
172
120
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 cCurrent 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.
110



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

The pension plans benefit obligation aActuarial losses of $98 (gain) of $ (173) million in 20123 and $14398 million in 20112 are primarily due to the impact of decreaschanges in the discount rates utilized to calculate the benefit obligations. TheIn 2012 benefit obligation actuarial 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 rate utilized to calculate the benefit obligation3, these rates increased, while in 2012 these rates decreased, as compared to those of the preceding year. The 20113 benefit obligation aActuarial loss of $48(gain) of $ (63) million for our other postretirement benefit plans is primarily due to the impact of a den increase in the discount rates utilized to calculate the benefit obligation. In 2011, the actuarial loss includes a curtailment gain of $4 million for our pension p as well as favorable claims experience. The Plans and $1 millionmendment for ourthe other postretirement benefit plans due to the spin-off of WPX.
At December31, 2012 and 2011, all of our pension plans had a projected benefit obligation and accumulated benefit obligation in excess of plan assets.
The determination of net perio
of $ (59) million in 2013 reflects a change in the plans to provide subsidized retiree medical benefit cost allows for the delayed recognition of gains and losses caused by differences betwes through defined annual contributions to health reimbursement actual and assumed outcomes for items such as estimated return on plan assets, or caused by changes in assumptions for items such as discount rates or estimated future compensation levels. The net actuarial loss presented in the following table and recorded in accumulated other comprehensive loss and net regulatory assets represents the cumulative net deferred loss from thcounts 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 changese types of diffo claims experiences or changes which have not yet be and health care cost trend recognized in net periodic benefit cost . A portion of the net actuarial loss is amortized over the participants average remaining future years of service, which is approximately 12years forates, offset by the impact of a decrease in the discount rates utilized to calculate the benefit obligation. At December31, 2013 and 2012 , all of our pension plans hand ap proximately 8years for our other postretirement benefit plans.
jected benefit obligation and accumulated benefit obligation in excess of plan assets. Pre-tax amounts not yet recognized in nNet periodic benefit cost at December31 are as follows:



Pension Benefits
Other
Postretirement
eeis
2013
2012
20113
2012
2011

(Millions)

Amounts included in aAccumulated other comprehensive income (loss)

Prior service (cost) credit
$
$
(1
)
$
(2
)
26
$
7
$
8

Net actuarial loss
(491
)
(828
)
(83511
)
(35
)
(40
)

Amounts included in
net regulatory assets/liabilities associated with our FERC-regulated gas pTransco and Northwest Pipelines:
Prior service credit
N/A
N/A
$
42
$
14
$
14

Net actuarial loss
N/A
N/A
(2
)
(67
)

(85
)
In addition to the net regulatory assets/liabilities included in the previous table, differences in the amount of actuarially determined nNet periodic benefit cost for our other postretirement benefit plans and the other postretirement benefit costs recovered in rates for our FERC-regulated gas pTransco and Northwest Pipelines are deferred as a regulatory asset or liability. We have net regulatory liabilities of $3844 million at December31, 20123 and $348 million at December31, 20112 related to these deferrals. These amounts will be reflected in future rates based on the gas pipelines rate structures.
121
Table of Contents
THE WILLIAMS COMPANIES
of these gas pipelines.
111



The Williams Companies
, INCnc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTSotes to Consolidated Financial Statements (Continued)

Net Periodic Benefit Cost
Net periodic benefit cost for the years ended December31 consist of the following:



Pension Benefits
Other
oteieetBnft

2013
2012
2011
20103
2012
2011
2010

(Millions)

Components of net periodic benefit cost:

Service cost
$
44
$
39
$
41
$
352
$
3
$
2
$
2

Interest cost
51
55
64
6411
13
15
15

Expected return on plan assets
(61
)
(64
)
(77
)
(719
)
(9
)
(10
)
(9
)

Amortization of prior service cost (credit)
1
1
1
(12
)
(7
)
(11
)
(14
)

Amortization of net actuarial loss
60
53
38
354
8
3
3

Net actuarial loss from settlements
5
4

AmortizReclassification tof regulatory asset
1
liability
2

1


Net periodic benefit cost
$
95
$
89
$
71
$
64(2
)

$
8
$
$
(2
)
Included in Net periodic benefit cost in 2011 in the previous table is cost associated with active and former employees that supported WPXs 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 December31 consist of the following:

Included in net periodic benefit cost in 2011 and 2010 in the previous table is cost associated with active and former employees that supported WPXs operations. This cost was directly charged to WPX and is included in income (loss) from discontinued operations . These amounts totaled $8 million in 2011 and $7 million in 2010 for our pension plans and totaled less than $1 million in 2011 and 2010 for our other postretirement benefit plans. The spin-off of WPX did not have a significant impact on net periodic benefit cost in 2012.
Items Recognized in Other Comprehensive Income (Loss)
Other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) before taxes for the years ended December31 consist of the following:


Pension Benefits
Other

oteieetBnft

2013
2012
2011
20103
2012
2011
2010

(Millions)

Other changes in plan assets and benefit obligations recognized in oOte opeesv noe(os

Net actuarial gain (loss)
$
277
$
(51
)
$
(220
)
$
(71
)
23
$
2
$
(21
)
$
(12
)

Prior service credit
23
2
2

Amortization of prior service cost (credit)
1
1
1
(4
)
(3
)
(4
)
(5
)

Amortization of net actuarial loss and loss from settlements
60
58
42
351
3
1
1


Other changes in plan assets and benefit obligations recognized in
oOther comprehensive income (loss)
$
338
$
8
$
(177
)
$
(35
)
43
$
4
$
(22
)
112



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)
$
(1662
$
13
$
(39
)

Prior service credit
36
4
1

Amortization of prior service credit
(8
)
(4
)
(7

)

Other changes in plan assets and benefit obligations for our other postretirement benefit plans associated with our FERC-regulated gas pipelines are recognized in net regulatory assets at December31, 2012, and include a net actuarial gain of $13million, prior service credit of $4 million, amortization of prior service credit of $4 million, and amortization of net actuarial loss of $5 million. At December31, 2011, amounts recognized in net regulatory assets included a net actuarial loss of $39 million, prior service credit of $1 million, amortization of prior service credit of $7 million, and amortization of net actuarial loss of $2 million. At December31, 2010, amounts recognized in net regulatory assets included a net actuarial loss of $10million, prior service credit of $1 million, amortization of prior service credit of $9million, and amortization of net actuarial loss of $2 million.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Amortization of net actuarial loss
3
5
2

Pre-tax amounts expected to be amortized in
nNet periodic benefit cost in 20134 are as follows:



Pension
Benefits
Other

Postretirement
eeis
(Millions)

Amounts included in aAccumulated other comprehensive income (loss)

Prior service cost (credit)
$
1
$
(38
)

Net actuarial loss
60
38

Amounts included in
net regulatory assets/liabilities associated with our FERC-regulated gas pTransco and Northwest Pipelines:
Prior service credit
N/A
$
(512
)

Net actuarial loss
N/A
6
Key Assumptions
The weighted-average assumptions utilized to determine benefit obligations as of December31 are as follows:



PensionBenefits
Other
Postretirement
eeis
2013
2012
20113
2012
2011

Discount rate
4.68
%
3.43
%
3.984.80
%
3.77
%
4.22
%

Rate of compensation increase
4.56
4.57
4.52
N/A
N/A
The weighted-average assumptions utilized to determine nNet periodic benefit cost for the years ended December31 are as follows:



Pension Benefits
Other
oteieetBnft

2013
2012
2011
20103
2012
2011
2010

Discount rate
3.43
%
3.98
%
5.19
%
5.783.97
%
4.22
%
5.35
%
5.80
%

Expected long-term rate of return on plan assets
5.90
6.30
7.50
7.505.26
5.71
6.54
6.51

Rate of compensation increase
4.57
4.52
5.00
5.00
N/A
N/A
N/A

The discount rates for our pension and other postretirement benefit plans were determined separately based on an approach specific to our plans. The year-end discount rates were determined considering a yield curve comprised of high-quality corporate bonds published by a large securities firm and the timing of the expected benefit cash flows of each plan. The deincrease in discount rates from December31, 20112 to December31, 20123 is primarily due to the general market declinincrease in yields on long-term, high-quality corporate debt securities.
The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized 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 and the target weightings of each asset class. The expected long-term rates of return on plan assets assumptions decreased in 20123 as a result of an increase in the fixed income securities asset allocation, as well as a decrease in the forward-looking capital market projections.
The expected return on plan assets component of net periodic benefit cost is calculated using the market-related value of plan assets. For assets held in our pension plans, the market-related value of plan assets is equal to the fair value of plan assets adjusted to reflect amortization of gains or losses associated with the difference
123
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
between the expected return on plan assets and the actual return on plan assets over a five-year period. Additionally, the market-related value of plan 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.
decrease in the forward-looking capital market projections.
113



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 20134 is 87.2 percent. This rate decreases to 5.0 percent by 2021. The health care cost trend rate assumption has a significant effect on the amounts reported3 . A one-percentage-point change in assumed health care cost trend rates would have the following effects:



Pointincrease
Pointdecrease

(Millions)

Effect on total of service and interest cost components
$
21
$
(21
)

Effect on other postretirement benefit obligation
467
(
386
)

Plan Assets
The investment policy for our pension and other postretirement benefit plans provides for an investment strategy in accordance with ERISAthe 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 December31, 20123 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. The
124
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
overall rating of the fixed income security assets is generally required to be at least A, according to the Moodys or Standard& Poors 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 20123, nineten 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
114



The Williams Companies, Inc.

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 December31, 20123 and 2011,2 by asset class are as follows:



2013

Quoted Prices
in Active
Marketsfor
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

Level1
Level2
Quoted Prices
in Active
Marketsfor
Identical
Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(
Level3 3)
Total

(Millions)

Pension assets:

Cash management fund (1)
$
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
6

Commingled investment funds:

Equities U.S. large cap (21) 146
146

Equities Emerging markets value (3)
33
33

Equities International developed markets large cap value (45) 83
83

Fixed income Corporate bonds (56) 150
150

Fixed income securities (67)

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


125
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

The fair values of our other postretirement benefits plan assets at December31, 2013 and 2012 by asset class are as follows:



20113

Level1
Level2
Quoted Prices
in Active
Marketsfor
Identical
Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(
Level3 3)
Total

(Millions)

PensionOther postretirement benefit ses

Cash management fund (1)s
$
413 $
$
$
413
Equity securities:

U.S. large cap
170
170
52
52


U.S. small cap
121
121
29
29


International developed markets large cap growth
4
57
61
15
15


Emerging markets growth
31
91
12
Commingled investment funds:

Equities U.S. large cap (21)
1
478
1
478

Equities International small cap (2)
2
2


Equities Emerging markets value (3)
4
4

Equities Emerging markets growth (4)
27
2
7

Equities International developed markets large cap value (
45)
69
69
10
10


Fixed income Corporate bonds (
56)
58
58
14
14


Fixed income securities (68)

U.S. Treasury securities
163
3

Government and municipal bonds
10

1
60

Mortgage-backed securities
65
65

Corporate bonds
169
169

Insurance company investment contracts and other
7
7

Corporate bonds
20
20

Total assets at fair value at December 31, 20113
$
35798
$
608103
$
$
965201
117



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)


The fair values of our other postretirement benefits plan assets at December31, 2012 and 2011, by asset class are as follows:


2012

Level1
Level2
Quoted Prices
in Active
Marketsfor
Identical
Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(
Level3 3)
Total

(Millions)

Other postretirement benefit assets:

Cash management funds (1)
$
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 (21) 15
15

Equities Emerging markets value (3)
3
3

Equities International developed markets large cap value (45) 9
9

Fixed income Corporate bonds (56) 15
15

Fixed income securities (78)

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
____________

126
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(1)
The stated intent of this fund is to invest primarily in equity securities comprising the Standard& Poors 500 Index. The investment objective of the fund is to approximate the performance of the Standard& Poors 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.

2011

Level1
Level2
Level3
Total
(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.


(Millions)

Other postretirement benefit assets:(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.


Cash management funds (1)
$
16
$
$
$
16

Equity securities:(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
118


U.S. large cap
42
42

U.S. small cap
20
20

International developed markets large cap growth
1
12
13
The Williams Companies, Inc.

Emerging markets growth
1
1
2
Notes to Consolidated Financial Statements (Continued)

Commingled investment funds: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.

Equities U.S. large cap (2)
15
15

Equities Emerging markets value (3)
3
3
(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.


Equities International developed markets large cap value (4)
7
7

Fixed income Corporate bonds (5)
6
6
(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 funds 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.


Fixed income securities (7):

U.S. Treasury securities
2
2
(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.


Government and municipal bonds
10
10

Mortgage-backed securities
6
6
(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 December31, 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.
119


Corporate bonds
17
17


T
otal assets at fair value at December 31, 2011
$
82
$
77
$
$
159
he Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

(1)
The stated intent of these funds is to invest in high credit quality, short-term corporate, and government money market debt securities that have remaining maturities of approximately one year or less, and are deemed to have minimal credit risk
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.
(2)
The stated intent of this fund is to invest primarily in equity securities comprising the Standard& Poors 500 Index. The investment objective of the fund is to approximate the performance of the Standard& Poors 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.

(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 ten 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 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 ten 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.
Pension Benefits
Other Postretirement Benefits


(5)
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 funds 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.

(6)
The weighted-average credit quality rating of the pension assets fixed income security portfolio is investment grade with a weighted-average duration of 5.7 years for 2012 and 5.6 years for 2011.

(7)
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 4.9 years for 2012 and 4.8 years for 2011.
127
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 estimated 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 December31, 2012 and 2011. Additionally, there were no transfers or reclassifications of investments between Level 1 and Level 2 from December 2011 to December 2012. If transfers between levels had occurred, the transfers would have been recognized as of the end of the period.
Plan Benefit Payments and Employer Contributions
Following are the expected benefits to be paid by the plans and the expected federal prescription drug subsidy to be received in the next ten years. 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
Federal
Prescription
Drug
Subsidy

(Millions)

20134
$
7788
$
16
$
(2
)
5

2014
86
17
(3
)

2015
926
1
8
(3
)
5

2016
97
18
(3
)
102
16


2017
103
1
9
(3
)
6

2018
109
17


20189-20223
591
107
(18
)
128
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
74
In 201
34, we expect to contribute approximately $960 million to our tax-qualified pension plans and approximately $13 million to our nonqualified pension plans, for a total of approximately $9163 million , and approximately $98 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 $257 million in 20123 , $285 million in 20112 , and $268 million in 20101 . Included in these amounts are2011 is $5 million in matching contributions for employees that supported WPXs operations that were directly charged to WPX and included in iIncome (loss) from discontinued operations that totaled $5 million for both 2011 and 2010.
Note 9.
. Note 10 Inventories



December 31,

December31,2013
2012
December31,
2011

(Millions)

Natural gas liquids, olefins, and natural gas in underground storage
$
111
$
97
$
98

Materials, supplies, and other
83
78
71


$
194
$
175
$
169
120



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

Note 11 Property, Plant, and Equipment


Note 10. Property, Plant, and Equipment


Estimated

UsefulLife (a)
1) (Years)
Depreciation

Rates (a)
1) %

December31,

2013
2012
2011

(Millions)

Nonregulated:

Natural gas gathering and processing facilities
5 - 40
$
9,185
$
7,727
$
6,435

Construction in progress
(b)Not applicable
3,123

1,997
648

Other
3-45
1,316
1,103
816

Regulated:

Natural gas transmission facilities
1.
201 - 6.8297
10,633

9,963
9,593

Construction in progress
(b)Not applicable
273

337
199

Other
.18-33.31.35-33.33
1,29
3 1,419
1,391


Total property, plant, and equipment, at cost
25,823
22,546
19,082

Accumulated depreciation and amortization
(7,613
)
(7,079
)
(6,502
)


Property, plant, and equipment net
$
18,210
$
15,467
$
12,580
__________


(1)
Estimated useful life and depreciation rates are presented as of December31, 2013 . Depreciation rates for regulated assets are prescribed by the FERC.
Depreciation and amortization expense for Property, 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 December31, 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)

(a)
Estimated useful life and depreciation rates are presented as of December31, 2012. Depreciation rates for regulated assets are prescribed by the FERC
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 December31, 2013 and 2012 , respectively.
(b)
Construction in progress balances not yet subject to depreciation.
Depreciation and amortization expense for property, plant, and equipment net was $712 million in 2012, $658 million in 2011, and $611 million in 2010.
129
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Regulated property, plant, and equipmentnet includes $825million and $865million at December31, 2012 and 2011, 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.
The following table presents the significant changes to our asset retirement obligations, of which $511million and $507million are included in other noncurrent liabilities with the remaining current portion in accrued liabilities at December31, 2012 and 2011, respectively.


December31,

2013
2012
2011

(Millions)

Beginning balance
$
579
$
573
$
499

Liabilities incurred
8
48

Liabilities settled (1)
(31
)

(44
)
(46
)

Accretion expense
53
43
39

Revisions (12)
(48
) (1
)
77


Ending balance
$
561
$
579
$
573
______________


(1)
The 2012 revision primariFor 2013 and 2012, liabilities settled include $25 million and $31 million , respectively, reflects a decrease in removal cost estimates, which is among slated to the abandonment of certain of Transcos natural gas storage caverns that are associated with a leak in 2010.


(2)
S
everal 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 in 2011 is primarily due toreflects increases in the inflation rate and estimatedestimated remaining useful life of the assets. The 2012 revision primarily reflects a decrease in removal cost estimates. The 20123 and 20112 revisions also include increases of $139 million and $139 million , respectively, related to changes in the timing and method of abandonment on certain of Transcos natural gas storage caverns that were associated with a leak in 2010.
Pursuant to its 2008 rate case settlement, Transco deposits a portion of its collected ra
Transco is entitled to collect in rates the amounts necessary to fund its ARO. All funds received for such retirements are depositesd into an external trust (ARO Trust) that is specifically designated to fund future account dedicated to funding its ARO (AROs. Transco was also required to make annual deposits into the trust through 2012. (See Note 15.)
130
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
ust). (See Note 16 Fair Value Measurements, Guarantees, and Concentration of Credit Risk .) Under its current rate settlement, Transcos annual funding obligation is approximately $36 million , with installments to be deposited monthly. Note 11.2 Accrued Liabilities



Dcme3,
2013
2012
2011

(Millions)

Interest on debt
$
167
$
148
$
143

Employee costs
127
137
127

Estimated rate refund liability
98

Asset retirement obligations
64
68
66

Other, including other loss contingencies
341
275
295


$
797
$
628
$
631
122



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

Note 13 Debt, Banking Arrangements, and Leases Long-Term Debt


Note 12. Debt, Banking Arrangements, and Leases
Long-Term Debt


December 3,
2013
2012
2011

(Millions)

Unsecured:

Transco:

8.875 6.4% Notes due 20126
$
200
$
325

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

Revolving credit5.8% Notes due 2043
400

Credit facility
on
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
90

Other, including secured capital lease obligations
1
2
4

Net unamortized debt discount
(37
)
(33
)
(32
)


Total long-term debt, including current portion
11,354
10,736
8,722

Long-term debt due within one year
(1
)
(3531
)


Long-term debt
$
11,353
$
10,735
$
8,369
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.
123


131
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
Credit Facilities
We have a $900 million senior unsecured revolving credit facility with a maturity date of June3, 2016. The credit facility may, under certain conditions, be increased up to an additional $250 million. 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 December31, 2012, we are in compliance with these financial covenants.
In September 2012, WPZ amended its existing $2 billion senior unsecured revolving credit facility to increase the aggregate commitments by $400 million. The maturity date of the amended credit facility is June3, 2016. This credit facility was also amended to provide that WPZ may request an additional $400 million increase in commitments to be available under certain conditions in the future. This credit facility includes Transco and Northwest Pipeline as co-borrowers and is only available to named borrowers. The full amount of the credit facility is available to WPZ to the extent not otherwise utilized by Transco and Northwest Pipeline. Transco and Northwest Pipeline each have access to borrow up to $400million under the credit facility to the extent not otherwise utilized by the other co-borrowers. Significant financial covenants include:

WPZs ratio of debt to EBITDA (each as defined in the credit facility) must 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 a ratio of debt to EBITDA of no greater than 5.5 to 1;The Williams Companies, Inc.

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 December31, 2012, WPZ is in compliance with these financial covenants.
The two credit agre
Notes to Consolidated Financial Statements c(Contain the following terms and conditions:ued)

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 0.25 percent for our agreement and 0.20 percent for the WPZ agreement) based on the unused portion of their respective credit facility. The applicable margin and the commitmeThe following table presents aggregate minimum maturities of long-term debt (excluding net unamortized discount) fee are determined for each borrower by reference to a pricing schedule based on such borrowers senior unsecured long-term debt ratings.or each of the next five years:

Various covenants may limit, among other things, a borrowers and its material subsidiaries ability to grant certain liens supporting indebtedness, a borrowers 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 their respective credit facility agreement, 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.
132
Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Letter of credit capacity under our $900 million and WPZs $2.4 billion credit facilities is $700 million and $1.3 billion, respectively. At December31, 2012, no letters of credit have been issued on either facility. No loans are outstanding on our credit facility at December31, 2012. Loans totaling $375 million are outstanding on WPZs credit facility at December31, 2012. We have issued letters of credit totaling $27 million as of December31, 2012, under certain bilateral bank agreements.
Issuances and Retirements
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. (See Note 2.)
In August 2012, WPZ completed a public offering of $750 million of 3.35 percent senior unsecured notes due 2022. WPZ used the net proceeds to repay outstanding borrowings on its senior unsecured revolving credit facility and for general partnership purposes.
In July 2012, Transco issued $400 million of 4.45 percent senior unsecured notes due 2042 to investors in a private debt placement. A portion of these proceeds was used to repay Transcos $325 million 8.875 percent senior unsecured notes that matured on July15, 2012. 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.
In August 2011, Transco issued $375 million of 5.4 percent senior unsecured notes due 2041 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 February 2012 and completed in March 2012.
Other Debt Disclosures
As of December31, 2012, aggregate minimum maturities of long-term debt (excluding capital leases and unamortized discount) for each of the next five years are as follows:

December31, 2013

(Millions)

2013
$

2014
$

2015
$
750

2016
$
3750

2017
$
785
Cash payments for interest were $539 million in 2012, $599 million in 2011 and $614 million in 2010.
We have considered the guidance in the Securities and Exchange Commissions 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 WPZs partnership agreement that govern the partnerships assets. Our interest in WPZs net assets at December31, 2012 was $6.2 billion.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Leases-Lessee
Future minimum annual rentals under noncancelable operating leases as of December31, 2012 are payable as follows:

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 Transcos $325 million of 8.875 percent senior unsecured notes that matured on July15, 2012. Credit Facilities On July31, 2013, we amended our $900 million and WPZs $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 July31, 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 December31, 2013 , letter of credit capacity under our $1.5 billion and WPZs $2.5 billion credit facilities is $700 million and $1.3 billion , respectively. At December31, 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 December31, 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 December31, 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
124



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

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 December31, 2013, WPZ is in compliance with these financial covenants. The credit agreements governing our and WPZs 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 borrowers senior unsecured long-term debt ratings.


Various covenants may limit, among other things, a borrowers and its material subsidiaries ability to grant certain liens supporting indebtedness, a borrowers 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 WPZs 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 December31, 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 Commissions 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 WPZs partnership agreement that govern the partnerships assets. Our interest in WPZs net assets at December31, 2013 was $ 6.5 billion .
125



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

Leases-Lessee The future minimum annual rentals under noncancelable operating leases, are payable as follows:



December31, 2013

(Millions)

20134
$
503

2014
44

2015
427

2016
435

2017
2736

2018
30


Thereafter
1
238


Total
$
33
62
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 years 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 March31, 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.
126



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

AOCI The following table presents the changes in AOCI by component, net of income taxes:


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 years per-unit NGL margins and the volume of gas gathered by our Williams Partners 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 March31, 2029.
Total rent expense was $56 million in 2012, $49 million in 2011, and $45 million in 2010.
Note 13 . Stockholders Equity
Cash dividends declared per common share were $1.19625, $.775 and $.485 for 2012, 2011, and 2010, respectively.
In April 2012, we issued approximately 30million 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 WPZs Caiman Acquisition. (See Note 2.)
In December 2012, we issued approximately 53million 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.)
At December31, 2012, approximately $2million of our original $300million, 5.5 percent junior subordinated convertible debentures, convertible into less than onemillion shares of common stock, remain outstanding. In 2012, 2011 and 2010, we converted $6 million, $14million and $2million, respectively, of the debentures in exchange for approximately one million, onemillion and less than onemillion shares, respectively, of common stock.
We maintain a Stockholder Rights Plan, as amended and restated on September21, 2004, and further amended May18, 2007, and October12, 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
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
was acquired inadvertently or without knowledge of the terms of the rights. The rights, which until exercised do not have voting rights, expire in 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.
AOCI
The following table presents the balances of the components of our AOCI, net of income taxes, as of December31:


2012
2011
Cash Flow Hedges
Foreign Currency Translation
Pensionand Other Post Retirement Benefits
Total


(Millions)

Cash flow hedgesBalance at December31, 2012
$
(1
)
$

Foreign currency translation
169
147

Pension and other postretirement benefits (see Note 8)
$
(530
)
(539$
(362
)

Other comprehensive income (loss) before reclassifications
1
(41

)
203
163

Equity securities
3
Amounts reclassified from accumulated other comprehensive income (loss)
(1
)
36
35


Other comprehensive income (loss)
(41
)
239
198

Total accumulated other comprehensive loss, net of income taxesBalance at December31, 2013
$
(1
)
$
128

$
(
362291
)
$
(
389164
) Reclassifications out of AOCI are presented in the following table by component for the year ended December31, 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 1
4.5 Stock-Based Compensation
Plan Information
On May17, 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 May20, 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 December31, 20123 , 274 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 164 million shares were available for future grants.
127



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

Additionally, on May17, 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 194203 thousand shares at an average price of $23.757.62 per share during 20123 . Approximately 616413 thousand shares were available for purchase under the ESPP at December31, 2012.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
3 . Total stock-based compensation expense for the years ended December31, 20123 , 20112 , and 20101 was $367 million , $5236 million , and $4852 million , respectively, of which $18 million and $14 million areis included in iIncome (loss) from discontinued operations for 2011 and 2010. 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 December31, 20123 , was $404 million , which does not include the effect of estimated forfeitures of $1 million . This amount is comprised of $34 million related to stock options and $3740 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 December31, 2012.3 :



SokOtos Options
Weighted-
Average
Exercise
Price
Aggregate

Intrinsic
au

(Millions)
(Millions)

Outstanding at December31, 201
12
9.66.9
$
1
5.639.10

Granted
1.10.9
$
29.1133.57

Exercised
(
3.81.1
)
$
13.2134

Outstanding at December31, 2013
6.7
$
21.82
$
112

OutstandingExercisable at December31, 20123
6.95.0
$
1
9.18.70 $
9
48
The total intrinsic value of options exercised during the years ended December31, 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 December31, 2013 , was 5.1 years and 3.9 years, respectively.
128



The Williams Companies, Inc.

Exercisable at December31, 2012
5.1
$
16.68
$
82
Notes to Consolidated Financial Statements (Continued)

The total intrinsic value of options exercised during the years ended December31, 2012, 2011, and 2010 was $69million, $55 million, and $20 million, respectively; and the tax benefit realized was $25million, $21million, and $7million, respectively. Cash received from stock option exercises was $50million, $45 million, and $7 million during 2012, 2011, and 2010, respectively. The weighted-average remaining contractual life for stock options outstanding and exercisable at December31, 2012, was 5.2 years and 4.0 years, respectively.
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
2010

Weighted-average grant date fair value of options for our common stock granted during the year, per share
$
5.94
$
5.65
$
6.28
$
5.71


Weighted-average assumptions:

Dividend yield
4.3
%
3.7
%
3.6
%
2.6
%

Volatility
29.7
%
30.0
%
34.6
%
39.0
%

Risk-free interest rate
1.4
%
1.3
%
2.8
%
3.0
%

Expected life (years)
6.5
6.5
6.5
The expected dividend yield is based on the 201
23 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 groups implied volatility. The adjustment is made because the difference in implied volatility between our peer group and us
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 December31, 2012.3 .



Rsrce tc nt usadn
Shares
Weighted-
Average
arau*
(Millions)

Nonvested at December 31, 201
12
5.23.9
$
14.1222.49

Granted
2.01.2
$
230.6143

Forfeited
(0.41
)
$
11.5527.27

Vested
(
2.91.5
)
$
17.842


Nonvested at December 31, 201
23
3.
95
$
2
2.497.16
______________



*
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
2010

Weighted-average grant date fair value of restricted stock units granted during the year, per share
$
30.43
$
20.61
$
23.31
$
16.37


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 December31, 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.
129



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

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.

Performance-based shares granted under the Plan represent 30 percent of nonvested restricted stock units outstanding at December31, 2012. 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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Table of Contents
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 15. Fair Value Measurements
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.


Fair Value Measurements Using

Carrying
Amount
Fair
Value
Quoted

PricesIn
Active
Marketsfor
Identical
Assets
(Level 1)
Significant

Other
Observable
Inputs
(Level 2)
Significant

Unobservable
Inputs
Lvl3

(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
3,21:
Measured on a recurring basis:

ARO Trust investments
$
18
$
18
$
18
$
$

Energy derivatives assets not designated as hedging instruments
5
5
5

Energy derivatives liabilities not designated as hedging instruments
(1
)
(1
)
(1
)

Additional disclosures:

Notes receivable and other
95
138
2
8
128

Long-term debt
, including current portion (a (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
130



The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

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 December31, 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 December31, 2013 . The carrying value of this receivable is $35 million at December31, 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 WilTels current owner and the term of the underlying obligation. The default rate is published by Moodys 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
131

Assets (liabilities) at December31, 2011:

Measured on a recurring basis:

ARO Trust investmentThe Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

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 WilTels lease performance, the maximum potential exposure is approximately $35 million , and $36 million at December31, 2013 and 2012 , respectively. Our exposure declines systematically throughout the remaining term of WilTels 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 December31, 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.



December31,

2013
2012

(Millions)

NGLs, natural gas, and related products and service
s $
25341
$
25411

Transportation of natural gas and related products
193
170

Income tax receivable
74
68

Other
66
39

Total

$
25674
$
$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 WPXs 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
132


Available-for-sale equity securities
24
24
24

Energy derivatives assets not designated as hedging instruments
1
1
1

Additional disclosures:The Williams Companies, Inc.

Notes
receivable and other
57
57
N/A
N/A
N/A
to Consolidated Financial Statements (Continued)

Long-term debt, including current portion (a)
(8,718
)
(10,043
)
N/A
N/A
N/A
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 WPXs collection of accrued interest from counterparties as well as WPXs 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 WPXs 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 WPXs 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 courts ruling and on April10, 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 Acts Risk Management Program following its inspection of the facility on June 24 through 28, 2013. The report notes the EPAs preliminary determinations about the facilitys 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.
133


Guarantee
(34
)
(32
)
N/A
N/A
N/A

(a)
Excludes capital leases
Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets and liabilities measured at fair value on a recurring basis
ARO Trust investments : Transco deposits a portion of its collected rates, pursuant to its 2008 rate case settlement, into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
on a recurring basis based on quoted net asset values, is classified as available-for-sale, and is reported in regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.
Energy derivatives : Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) contracts, which consist 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 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 December31, 2012 or 2011.
Additional fair value disclosures
Notes receivable and other: Notes receivable and other includes a receivable related to the sale of certain former Venezuela assets. To determine the disclosed fair value of this receivable at December31, 2012, we considered 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 $93 million at December31, 2012. The carrying value of this receivable is $49 million at December31, 2012. The current and noncurrent portions are reported in accounts and notes receivable and regulatory assets, deferred charges, and other , respectively, in the Consolidated Balance Sheet.
Notes receivable and other also includes a receivable from our former affiliate, WPX (see Note 17) and other notes receivable. The disclosed fair value of these receivables is determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion is reported in accounts and notes receivable , and the noncurrent portion is reported in regulatory assets, deferred charges, and other in the Consolidated Balance Sheet.
Long-term debt : The disclosed fair value of our long-term debt is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.
Guarantee : The guarantee represented in the table consists of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042.
To estimate the disclosed fair value of the guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTels current owner and the term of the underlying obligation. The default rate is published by Moodys Investors Service. This guarantee is reported in accrued liabilities in the Consolidated Balance Sheet.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Guarantees
We are required by our revolving credit agreements to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.
Regarding our previously described guarantee of Wiltels lease performance, the maximum potential exposure is approximately $36 million at December31, 2012 and $38 million at December31, 2011. Our exposure declines systematically throughout the remaining term of WilTels obligation.
We have provided guarantees in the event of nonpayment by our previously owned subsidiary, WPX, on certain contracts, primarily including a long-term transportation capacity agreement and a natural gas purchase contract, extending through 2017 and 2023, respectively. We estimate the maximum undiscounted potential future payment obligation under these remaining guarantees is approximately $232 million at December31, 2012. Our recorded liability for these guarantees, which considers our estimate of the fair value of the guarantees, is insignificant.
Note 16. Derivative Instruments and Concentration of Credit Risk
Energy Commodity Derivatives
Risk management activities
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage our exposure to the variability in expected future cash flows from forecasted purchases and/or sales of natural gas, NGLs and olefins attributable to commodity price risk. The energy commodity derivatives in our current portfolio have not been designated as cash flow hedges or do not qualify for hedge accounting despite hedging our future cash flows on an economic basis.
We produce and sell NGLs and olefins at different locations throughout North America. We also buy natural gas to satisfy the required fuel and shrink needed to generate NGLs. In addition, we buy NGLs as feedstock to generate olefins. To reduce exposure to a decrease in revenues from fluctuations in NGL and olefin market prices or increases in costs and operating expenses from fluctuations in natural gas and NGL market prices, we may enter into NGL, olefin or natural gas swap agreements, futures contracts, financial or physical forward contracts, and financial option contracts to mitigate the price risk on forecasted sales of NGLs and olefins and purchases of natural gas and NGLs. Those designated as cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item.
Volumes
Our energy commodity derivatives are comprised of both contracts to purchase the commodity (long positions) and contracts to sell the commodity (short positions). Derivative transactions are categorized into two types:

Central hub risk: Financial derivative exposures to Mont Belvieu for NGLs;The Williams Companies, Inc.

Basis risk: Financial and physical derivative exposures to the difference in value between the central hub and another specific delivery point.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table depicts the notional quantities of the net long (short) positions in our commodity derivatives portfolio as of December31, 2012. NGLs are presented in barrels.
Notes to Consolidated Financial Statements (Continued)

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 January28, 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 December31, 2008, by $43 million , including $11 million of interest. On February17, 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 December31, 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 May8, 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 others claims. On November 5, 2013, the court ruled that the applicable statute of limitations bars all FHRAs 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 courts 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.
134

Derivative Notional Volumes
Unit of
Measure
CentralHub
Risk
Basis Risk

Not Designated as Hedging Instruments

The Williams Partners
Barrels
(185,000
)
(38,256,000
)
Gains (losses)
The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in AOCI, product sales, or product costs
Companies, Inc.
Notes to Consolidated Financial Statements (Continued)

YearsendedDecember31,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 refinerys 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 August31, 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 December31, 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 December31, 2013 , we have accrued liabilities of $13 million for these costs.We expect that these costs will be recoverable through rates.
135


2012
2011
Classification

(Millions)

Net gain (loss) recognized in other comprehensive income (loss) (effective portion)
$
30
$
(18
)
AOCI
The Williams Companies, Inc.

Notes to Consolidated Financial Statements (Continued)

Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion)
$
30
$
(18
)
ProductSalesor Product Costs
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
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December31, 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 notes receivable
The following table summarizes concent
her liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of receivables, net of allowances, by product or service at December31, 2012 and 2011:the assets and businesses described below.


December31,Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;

2012
2011

(Millions)Former petroleum products and natural gas pipelines;

Receivables by product or service:

Sale of NGLs and related products and services
$
411
$
446
Former petroleum refining facilities;

Transportation of natural gas and related products
170
164

Other
107
27
Former exploration and production and mining operations;


Total
$
688
$
637
Former electricity and natural gas marketing and trading operations. At December31, 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 December31, 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 December31, 2013 .
136


Customers include producers, distribution companies, industrial users, gas marketers and pipelines primarily located in the central, eastern and northwestern United States, Rocky Mountains, Gulf Coast, and Canada. As a general policy, collateral is not required for receivables, but customers financial condition and credit worthiness are evaluated regularly.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Revenues
In 2012, 2011, and 2010, we had one customer in our Williams Partners segment that accounted for 14percent, 17 percent and 15 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 retained applicable accrued asset and liability balances associated with these matters, and as a result, have an indirect exposure to future developments in these matters.
Issues resulting from California energy crisis
WPXs 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 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 WPXs collection of accrued interest from counterparties as well as WPXs payment of accrued interest on refund amounts. As currently contemplated by the parties, the settlement, which is subject to FERC and California regulatory approval, would resolve most of WPXs legal issues arising from the 2000-2001 California Energy Crisis. We currently have a net receivable from WPX related to these matters.
Certain other issues also remain open at the FERC and for other nonsettling parties.
Reporting of natural gas-related information to trade publications
Civil suits based on allegations of manipulating published gas price indices have been brought against WPX and others, in each case seeking an unspecified amount of damages. WPX is currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri, and Wisconsin brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of WPX and most of the other defendants based on plaintiffs lack of standing. In 2009, the court denied the plaintiffs request for reconsideration of the Colorado dismissal and entered judgment in WPXs favor. The courts order became final on July18, 2011, and the Colorado plaintiffs might appeal the order.
In the other cases, on July18, 2011, the Nevada district court granted WPXs joint motions for summary judgment to preclude the plaintiffs state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs class certification motion as moot. In 2011, the plaintiffs appealed the courts ruling to the Ninth Circuit Court of Appeals, and in early 2012, the parties completed briefing the issues. A decision is expected in 2013. Because of the uncertainty around these current pending unresolved issues, including an insufficient description of the purported classes and other related
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
matters, we cannot reasonably estimate a range of potential exposures at this time. However, it is reasonably possible that the ultimate resolution of these items and our related indemnification obligation could result in future charges that may be material to our results of operations.
Other Legal Matters
Gulf Liquids litigation
Gulf Liquids contracted with Gulsby Engineering Inc. (Gulsby) and Gulsby-Bay (a joint venture between Gulsby and Bay Ltd.) for the construction of certain gas processing plants in Louisiana. National American Insurance Company (NAICO) and American Home Assurance Company provided payment and performance bonds for the projects. In 2001, the contractors and sureties filed multiple cases in Louisiana and Texas against Gulf Liquids and us.
In 2006, at the conclusion of the consolidated trial of the asserted contract and tort claims, the jury returned its actual and punitive damages verdict against us and Gulf Liquids. Based on our interpretation of the jury verdicts, we recorded a charge based on our estimated exposure for actual damages of approximately $68million 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 $199million 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 January28, 2008, the court issued its judgment awarding damages against Gulf Liquids of approximately $11million in favor of Gulsby and approximately $4million 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 December31, 2008, by $43million, including $11million of interest. On February17, 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 December31, 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 May8, 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.
Alaska refinery contamination litigation
In January 2010, James West filed a class action lawsuit in state court in Fairbanks, Alaska on behalf of individual property owners whose water contained sulfolane contamination allegedly emanating from the Flint Hills Oil Refinery in North Pole, Alaska. The suit named our subsidiary, Williams Alaska Petroleum Inc. (WAPI), and Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., as defendants. We owned and operated the refinery until 2004 when we sold it to FHRA. We and FHRA have made claims under the pollution liability insurance policy issued in connection with the sale of the North Pole refinery to FHRA. We and FHRA also filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination.
In August 2010, the court denied Wests request for class certification. On May5, 2011, we and FHRA settled the James West claim, leaving FHRA and Williams claims. We filed motions for summary judgment on FHRAs claims against us, but the motions are unlikely to resolve all the outstanding claims. Similarly, FHRA has filed motions for summary judgment that would resolve some, but not all, of our claims against it. An April 2013 trial date had been scheduled, but has been stricken and has not been reset.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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. We might have the ability to recover any such losses under the pollution liability policy if FHRA has not exhausted the policy limits.
Independent of the litigation matter described in the preceding paragraphs, during the fourth quarter 2012, the Alaska Department of Environmental Conservation (ADEC) requested that we and the FHRA voluntarily enter into a compliance order by consent with it for environmental remediation of sulfolane and other possible contaminants. Discussions on these issues are ongoing. ADEC has indicated that it views us and FHRA as responsible parties. As such, we will likely be required to contribute some amount, whether to reimburse the State, to reimburse FHRA, or to comply with an ADEC order. Due to the ongoing assessment of the level and extent of sulfolane contamination and the ultimate cost of remediation and division of costs between the named responsible parties, we are unable to estimate a range of liability at this time.
Other
In 2003, we entered into an agreement to sublease certain underground storage facilities to Liberty Gas Storage (Liberty). We have asserted claims against Liberty for prematurely terminating the sublease and for damage caused to the facilities. In February 2011, Liberty asserted a counterclaim for costs in excess of $200million associated with its use of the facilities. Due to the lack of information currently available, we are unable to evaluate the merits of the counterclaim and determine the amount of any possible liability.
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December31, 2012, we have accrued liabilities totaling $46 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered and the final cleanup standards mandated by the EPA and other governmental authorities.
The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules.More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, and one hour nitrogen dioxide emission limits.We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
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THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Continuing operations
Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances.These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites.At December31, 2012, we have accrued liabilities of $10 million for these costs.We expect that these costs will be recoverable through rates.
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December31, 2012, we have accrued liabilities totaling $7million 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; The Williams Companies, Inc.

Former petroleum refining facilities;Notes to Consolidated Financial Statements (Continued)

Former exploration and production and mining operations;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.

Former electricity and natural gas marketing and trading operations.
At December31, 2012, we have accrued environmental liabilities of $29million 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 December31, 2012, other than as previously disclosed, we are not aware of any material claims involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Summary
We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties.
Commitments
Commitments for construction and acquisition of property, plant, and equipment are approximately $1.3billion at December31, 2012.
Note 18. Segment Disclosures
Our reporting segments are Williams Partners, Williams NGL& Petchem Services, and Access Midstream Partners. All remaining business activities are included in Other. Following completion of WPZs purchase of the olefins production facility in Geismar, Louisiana, during the fourth quarter of 2012, the former Midstream Canada& Olefins segment is renamed Williams NGL& Petchem Services. All prior periods have been recast to reflect this transaction. (See Note 1.)
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.
On December20, 2012, we acquired an approximate 24 percent ownership interest in ACMP and a 50percent indirect interest in Access GP for approximately $2.19 billion.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 will add diversity to our current asset base.
Performance Measurement
We currently evaluate performance based upon segment profit (loss) from operations, which includes segment revenues from external and internal customers, segment costs and expenses, equity earnings (losses) and income (loss) from investments . General corporate expenses represent selling, general, and administrative expenses that are not allocated to our segments. The accounting policies of the segments are the same as those described in Note 1. Intersegment sales are generally accounted for at current market prices as if the sales were to unaffiliated third parties.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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
OtherCanada
Total

(Millions)

Revenues from external customers:

2013
$
6,703
$
157
$
6,860

2012
$
7,335
$
151
$
7,486

2011
7,728
202
7,930

2010
6,471
167
6,638

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 o