WMB_2013.12.31_10K


 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2013
 
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from                      to                     
Commission file number 1-4174
The Williams Companies, Inc.
(Exact Name of Registrant as Specified in Its Charter)
Delaware
 
73-0569878
(State or Other Jurisdiction of
Incorporation or Organization)
 
(IRS Employer
Identification No.)
 
 
 
One Williams Center, Tulsa, Oklahoma
 
74172
(Address of Principal Executive Offices)
 
(Zip Code)
918-573-2000
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Each Exchange on Which Registered
Common Stock, $1.00 par value
 
New York Stock Exchange
Preferred Stock Purchase Rights
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
5.50% Junior Subordinated Convertible Debentures due 2033
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes þ    No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  þ
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer þ
 
Accelerated filer ¨
 
 
Non-accelerated filer ¨
 
Smaller reporting company ¨
 
 
 
 

 
(Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  þ
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of the last business day of the registrant’s most recently completed second quarter was approximately $22,144,393,171.
The number of shares outstanding of the registrant’s common stock outstanding at February 21, 2014 was 684,417,475.

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



THE WILLIAMS COMPANIES, INC.
FORM 10-K

TABLE OF CONTENTS
 
 
Page
PART I
 
 
 
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
 
PART II
 
 
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
PART III
 
 
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
PART IV
 
 
 
 
Item 15.

1



DEFINITIONS

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

Measurements:
Barrel: One barrel of petroleum products that equals 42 U.S. gallons
BPD: Barrels per day
Bcf : One billion cubic feet of natural gas
Bcf/d: One billion cubic feet of natural gas per day
British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree
Fahrenheit
Dekatherms (Dth): A unit of energy equal to one million British thermal units
Mbbls/d: One thousand barrels per day
Mdth/d: One thousand dekatherms per day
MMcf/d: One million cubic feet per day
MMdth: One million dekatherms or approximately one trillion British thermal units
MMdth/d: One million dekatherms per day
TBtu: One trillion British thermal units
Consolidated Entities:
Bluegrass Pipeline: Bluegrass Pipeline Company LLC
Constitution: Constitution Pipeline Company, LLC
Gulfstar One: Gulfstar One LLC
Northwest Pipeline: Northwest Pipeline LLC
Transco: Transcontinental Gas Pipe Line Company, LLC
WPZ: Williams Partners L.P.
Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which we account
for as an equity investment, including principally the following:
Access GP: Access Midstream Partners GP, L.L.C.
Access Midstream Partners: Access GP and ACMP
Accroven: Accroven SRL
ACMP: Access Midstream Partners, L.P.
Aux Sable: Aux Sable Liquid Products LP
Caiman II: Caiman Energy II, LLC
Discovery: Discovery Producer Services LLC
Gulfstream: Gulfstream Natural Gas System, L.L.C.
Laurel Mountain: Laurel Mountain Midstream, LLC
OPPL: Overland Pass Pipeline Company LLC


2



Government and Regulatory:
Code, the: Internal Revenue Code of 1986
EPA: Environmental Protection Agency
Exchange Act, the: Securities and Exchange Act of 1934, as amended
FERC: Federal Energy Regulatory Commission
IRS: Internal Revenue Service
SEC: Securities and Exchange Commission
Other:
B/B Splitter: Butylene/Butane splitter
Caiman Acquisition: WPZ’s April 2012 purchase of 100 percent of Caiman Eastern Midstream, LLC located in
the Ohio River Valley area of the Marcellus Shale region
DAC: Debutanized aromatic concentrate
Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products,
such as ethane, propane, and butane
IDR: Incentive distribution right
Laser Acquisition: WPZ’s February 2012 purchase from Delphi Midstream Partners, LLC of 100 percent of
certain entities that operate in Susquehanna County, PA and southern New York
LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures
NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are
used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications
NGL margins:  NGL revenues less Btu replacement cost, plant fuel, transportation, and fractionation     
Throughput:  The volume of product transported or passing through a pipeline, plant, terminal, or other facility

3



PART I
Item 1. Business
In this report, Williams (which includes The Williams Companies, Inc. and, unless the context otherwise indicates, all of our subsidiaries) is at times referred to in the first person as “we,” “us” or “our.” We also sometimes refer to Williams as the “Company.”
WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION
We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents electronically with the SEC under the Exchange Act. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SEC’s Internet website at www.sec.gov.
Our Internet website is www.williams.com. We make available free of charge through the Investor tab of our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Code of Ethics for Senior Officers, Board committee charters and the Williams Code of Business Conduct are also available on our Internet website. We will also provide, free of charge, a copy of any of our corporate documents listed above upon written request to our Corporate Secretary, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
GENERAL
We are primarily an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas, NGLs, and olefins. Our operations are located principally in the United States, but span from the deepwater Gulf of Mexico to the Canadian oil sands.
Our interstate gas pipelines, domestic midstream, and domestic olefins production interests are largely held through our significant investment in Williams Partners L.P. (WPZ), one of the largest energy master limited partnerships. As of December 31, 2013, we own the general partner interest and a 62 percent limited-partner interest in WPZ. We also own a Canadian midstream business, which processes oil sands and offgas and produces olefins for petrochemical feedstocks, as well as a significant equity investment in Access Midstream Partners, which owns midstream assets in major unconventional producing areas.
We were founded in 1908, originally incorporated under the laws of the state of Nevada in 1949 and reincorporated under the laws of the state of Delaware in 1987. Williams’ headquarters are located in Tulsa, Oklahoma, with other major offices in Salt Lake City, Houston, the Four Corners Area, and Pennsylvania. Our telephone number is 918-573-2000.
DIVIDENDS
We increased our quarterly dividends from $0.325 per share in the fourth quarter of 2012 to $0.38 per share in the fourth quarter of 2013. Our Board of Directors has approved a dividend of $0.40250 per share for the first quarter of 2014.
FINANCIAL INFORMATION ABOUT SEGMENTS
See “Item 8 — Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — Note 18 – Segment Disclosures” for information with respect to each segment’s revenues, profits or losses and total assets.

4



BUSINESS SEGMENTS
Substantially all our operations are conducted through our subsidiaries. Our activities in 2013 were primarily operated through the following business segments:
•
Williams Partners — comprised of our master limited partnership WPZ, which includes gas pipeline and domestic midstream businesses. The gas pipeline business includes interstate natural gas pipelines and pipeline joint project investments, and the midstream business provides natural gas gathering, treating and processing services; NGL production, fractionation, storage, marketing and transportation; deepwater production handling and crude oil transportation services; an olefin production business and is comprised of several wholly owned and partially owned subsidiaries and joint project investments.
•
Williams NGL & Petchem Services — primarily comprised of our Canadian midstream operations and certain domestic olefins pipeline assets. Our Canadian assets include an oil sands offgas processing plant near Fort McMurray, Alberta, an NGL/olefin fractionation facility and B/B splitter facility at Redwater, Alberta, the Boreal Pipeline, certain Canadian growth projects including a propane dehydrogenation facility, and the Bluegrass Pipeline, a new joint project, which would connect processing facilities in the Marcellus and Utica shale-gas areas in the U.S. Northeast to growing petrochemical and export markets in the U.S. Gulf Coast.
•
Access Midstream Partners — comprised of an indirect equity interest in Access GP and limited partner interests in ACMP, which we purchased in the fourth quarter of 2012. ACMP is a publicly traded master limited partnership that provides gathering, processing, treating and compression services to Chesapeake Energy Corporation and other producers under long-term, fee-based contracts. Access GP is the general partner of ACMP. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets of Notes to Consolidated Financial Statements.)
•
Other — primarily comprised of corporate operations.
This report is organized to reflect this structure. Detailed discussion of each of our business segments follows. For a discussion of our ongoing expansion projects, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Williams Partners
Gas Pipeline Business
Williams Partners' gas pipeline businesses consist primarily of Transco and Northwest Pipeline. Our gas pipeline business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent interest in Gulfstream and a 41 percent interest in Constitution. Transco and Northwest Pipeline own and operate a combined total of approximately 13,600 miles of pipelines with a total annual throughput of approximately 3,870 TBtu of natural gas and peak-day delivery capacity of approximately 14 MMdth of natural gas.
Transco
Transco is an interstate natural gas transmission company that owns and operates a 9,700-mile natural gas pipeline system extending from Texas, Louisiana, Mississippi and the offshore Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and 12 southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, Washington, D.C., Maryland, New York, New Jersey, and Pennsylvania.
Pipeline system and customers
At December 31, 2013, Transco’s system had a mainline delivery capacity of approximately 5.9 MMdth of natural gas per day from its production areas to its primary markets, including delivery capacity from the mainline to locations on its Mobile Bay Lateral. Using its Leidy Line along with market-area storage and transportation capacity, Transco can deliver an additional 4.3 MMdth of natural gas per day for a system-wide delivery capacity

5



total of approximately 10.2 MMdth of natural gas per day. Transco’s system includes 45 compressor stations, four underground storage fields, and an LNG storage facility. Compression facilities at sea level-rated capacity total approximately 1.7 million horsepower.
Transco’s major natural gas transportation customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on Transco’s system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Transco’s firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Transco’s business. Additionally, Transco offers interruptible transportation services under shorter-term agreements.
Transco has natural gas storage capacity in four underground storage fields located on or near its pipeline system or market areas and operates two of these storage fields. Transco also has storage capacity in an LNG storage facility that we own and operate. The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 200 Bcf of natural gas. At December 31, 2013, our customers had stored in our facilities approximately 143 Bcf of natural gas. In addition, wholly owned subsidiaries of Transco operate and hold a 35 percent ownership interest in Pine Needle LNG Company, LLC, an LNG storage facility with 4 Bcf of storage capacity. Storage capacity permits Transco’s customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.
Northwest Pipeline
Northwest Pipeline is an interstate natural gas transmission company that owns and operates a natural gas pipeline system extending from the San Juan basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon, and Washington to a point on the Canadian border near Sumas, Washington. Northwest Pipeline provides services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California, and Arizona directly or indirectly through interconnections with other pipelines.
Pipeline system and customers
At December 31, 2013, Northwest Pipeline’s system, having long-term firm transportation and storage redelivery agreements of approximately 3.9 MMdth/d, was composed of approximately 3,900 miles of mainline and lateral transmission pipelines and 41 transmission compressor stations having a combined sea level-rated capacity of approximately 472,000 horsepower.
Northwest Pipeline transports and stores natural gas for a broad mix of customers, including local natural gas distribution companies, municipal utilities, direct industrial users, electric power generators and natural gas marketers and producers. Northwest Pipeline’s firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of Northwest Pipeline’s business. Additionally, Northwest Pipeline offers interruptible and short-term firm transportation service.
Northwest Pipeline owns a one-third interest in the Jackson Prairie underground storage facility in Washington and contracts with a third party for storage service in the Clay basin underground field in Utah. Northwest Pipeline also owns and operates an LNG storage facility in Washington. These storage facilities have an aggregate working gas storage capacity of 14.2 MMdth of natural gas, which is substantially utilized for third-party natural gas. These natural gas storage facilities enable Northwest Pipeline to balance daily receipts and deliveries and provide storage services to certain customers.
Gulfstream
Gulfstream is an interstate natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida. Williams Partners owns, through a subsidiary, a 50 percent interest in Gulfstream. Spectra Energy Corporation, through its subsidiary, Spectra Energy Partners, LP, owns the other 50 percent interest. Williams Partners shares operating responsibilities for Gulfstream with Spectra Energy Corporation.

6



Midstream Business
Williams Partners’ midstream business, one of the nation’s largest natural gas gatherers and processors, has primary service areas concentrated in major producing basins in Colorado, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio. The primary businesses are: (1) natural gas gathering, treating, and processing; (2) NGL fractionation, storage and transportation; (3) oil transportation; and (4) olefins production. These fall within the middle of the process of taking raw natural gas and crude oil from the producing fields to the consumer.
Key variables for this business will continue to be:
•
Retaining and attracting customers by continuing to provide reliable services;
•
Revenue growth associated with additional infrastructure either completed or currently under construction;
•
Disciplined growth in core service areas and new step-out areas;
•
Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;
•
Prices impacting commodity-based activities.
Gathering, Processing, and Treating
Williams Partners’ gathering systems receive natural gas from producers’ oil and natural gas wells and gather these volumes to gas processing, treating or redelivery facilities. Typically, natural gas, in its raw form, is not acceptable for transportation in major interstate natural gas pipelines or for commercial use as a fuel. Williams Partners’ treating facilities remove water vapor, carbon dioxide, and other contaminants and collect condensate, but do not extract NGLs. Williams Partners’ is generally paid a fee based on the volume of natural gas gathered and/or treated, generally measured in the Btu heating value.
In addition, natural gas contains various amounts of NGLs, which generally have a higher value when separated from the natural gas stream. Our processing plants extract the NGLs in addition to removing water vapor, carbon dioxide, and other contaminants. NGL products include:
•
Ethane, primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic building blocks for plastics;
•
Propane, used for heating, fuel and as a petrochemical feedstock in the production of ethylene and propylene, another building block for petrochemical-based products such as carpets, packing materials, and molded plastic parts;
•
Normal butane, isobutane and natural gasoline, primarily used by the refining industry as blending stocks for motor gasoline or as a petrochemical feedstock.
Our gas processing services generate revenues primarily from the following three types of contracts:
•
Fee-based: We are paid a fee based on the volume of natural gas processed, generally measured in the Btu heating value. Our customers are entitled to the NGLs produced in connection with this type of processing agreement. Beginning in 2013, a portion of our fee-based processing revenues includes a share of the margins on the NGLs produced. For the year ended December 31, 2013, 72 percent of the NGL production volumes were under fee-based contracts.
•
Keep-whole: Under keep-whole contracts, we (1) process natural gas produced by customers, (2) retain some or all of the extracted NGLs as compensation for our services, (3) replace the Btu content of the retained NGLs that were extracted during processing with natural gas purchases, also known as shrink replacement gas, and (4) deliver an equivalent Btu content of natural gas for customers at the plant outlet. NGLs we retain in

7



connection with this type of processing agreement are referred to as our equity NGL production. Under these agreements, we have commodity price exposure on the difference between NGL and natural gas prices. For the year ended December 31, 2013, 26 percent of the NGL production volumes were under keep-whole contracts.
•
Percent-of-Liquids: Under percent-of-liquids processing contracts, we (1) process natural gas produced by customers, (2) deliver to customers an agreed-upon percentage of the extracted NGLs, (3) retain a portion of the extracted NGLs as compensation for our services, and (4) deliver natural gas to customers at the plant outlet. Under this type of contract, we are not required to replace the Btu content of the retained NGLs that were extracted during processing, and are therefore only exposed to NGL price movements. NGLs we retain in connection with this type of processing agreement are also referred to as our equity NGL production. For the year ended December 31, 2013, 2 percent of the NGL production volumes were under percent-of-liquids contracts.
Our gathering and processing agreements have terms ranging from month-to-month to the life of the producing lease. Generally, our gathering and processing agreements are long-term agreements.
Demand for gas gathering and processing services is dependent on producers’ drilling activities, which is impacted by the strength of the economy, natural gas prices, and the resulting demand for natural gas by manufacturing and industrial companies and consumers. Williams Partners’ gas gathering and processing customers are generally natural gas producers who have proved and/or producing natural gas fields in the areas surrounding its infrastructure. During 2013, Williams Partners’ facilities gathered and processed gas for approximately 220 customers. Williams Partners’ top five gathering and processing customers accounted for approximately 50 percent of our gathering and processing revenue.
Demand for our equity NGLs is affected by economic conditions and the resulting demand from industries using these commodities to produce petrochemical-based products such as plastics, carpets, packing materials and blending stocks for motor gasoline and the demand from consumers using these commodities for heating and fuel. NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks.
Geographically, the midstream natural gas assets are positioned to maximize commercial and operational synergies with our other assets. For example, most of the offshore gathering and processing assets attach and process or condition natural gas supplies delivered to the Transco pipeline. Our San Juan basin, southwest Wyoming, and Piceance systems are capable of delivering residue gas volumes into Northwest Pipeline’s interstate system in addition to third-party interstate systems. Our gathering system in Pennsylvania delivers residue gas volumes into Transco’s pipeline in addition to third-party interstate systems.
Williams Partners owns and operates gas gathering, processing and treating assets within the states of Wyoming, Colorado, New Mexico, Pennsylvania, West Virginia, New York, and Ohio. We also own and operate gas gathering and processing assets and pipelines primarily within the onshore, offshore shelf, and deepwater areas in and around the Gulf Coast states of Texas, Louisiana, Mississippi, and Alabama.

8



The following table summarizes our significant operated natural gas gathering assets as of December 31, 2013:
 
Natural Gas Gathering Assets
 
Location
 
Pipeline
Miles
 
Inlet
Capacity
(Bcf/d)
 
Ownership
Interest
 
Supply Basins
West
 
 
 
 
 
 
 
 
 
Rocky Mountain
Wyoming
 
3,587
 
1.1
 
100%
 
Wamsutter & SW Wyoming
Four Corners
Colorado & New Mexico
 
3,841
 
1.8
 
100%
 
San Juan
Piceance
Colorado
 
328
 
1.4
 
(2)
 
Piceance
Northeast
 
 
 
 
 
 
 
 
 
Ohio Valley
West Virginia
 
174
 
0.8
 
100%
 
Appalachian
Susquehanna Supply Hub
Pennsylvania & New York
 
277
 
2.3
 
100%
 
Appalachian
Laurel Mountain (1)
Pennsylvania
 
2,044
 
0.7
 
51%
 
Appalachian
Atlantic-Gulf
 
 
 
 
 
 
 
 
 
Canyon Chief & Blind Faith
Deepwater Gulf of Mexico
 
139
 
0.5
 
100%
 
Eastern Gulf of Mexico
Seahawk
Deepwater Gulf of Mexico
 
115
 
0.4
 
100%
 
Western Gulf of Mexico
Perdido Norte
Deepwater Gulf of Mexico
 
105
 
0.3
 
100%
 
Western Gulf of Mexico
Offshore shelf & other
Gulf of Mexico
 
46
 
0.2
 
100%
 
Eastern Gulf of Mexico
Offshore shelf & other
Gulf of Mexico
 
208
 
1.1
 
100%
 
Western Gulf of Mexico
Discovery (1)
Gulf of Mexico
 
358
 
0.6
 
60%
 
Central Gulf of Mexico
_______________
(1)
Statistics reflect 100 percent of the assets from the jointly owned investments that we operate; however, our financial statements report equity method income from these investments based on our equity ownership percentage.
(2)
We own 60 percent of a gathering system in the Ryan Gulch area, which we operate, with 140 miles of pipeline and 200 MMcf/d of inlet capacity. We own and operate 100 percent of the balance of the Piceance gathering system.
In addition, we own and operate several natural gas treating facilities in New Mexico, Colorado, Texas, and Louisiana which bring natural gas to specifications allowable by major interstate pipelines. At our Milagro treating facility, we also use gas-driven turbines that have the capacity to produce 60 mega-watts per day of electricity which we primarily sell into the local electrical grid.
The following table summarizes our significant operated natural gas processing facilities as of December 31, 2013:
 
Natural Gas Processing Facilities
 
Location
 
Inlet
Capacity
(Bcf/d)
 
NGL
Production
Capacity
(Mbbls/d)
 
Ownership
Interest
 
Supply Basins
West
 
 
 
 
 
 
 
 
 
Opal
Opal, WY
 
1.5
 
70
 
100%
 
SW Wyoming
Echo Springs
Echo Springs, WY
 
0.7
 
58
 
100%
 
Wamsutter
Ignacio
Ignacio, CO
 
0.5
 
23
 
100%
 
San Juan
Kutz
Bloomfield, NM
 
0.2
 
12
 
100%
 
San Juan
Willow Creek
Rio Blanco County, CO
 
0.5
 
30
 
100%
 
Piceance
Parachute
Garfield County, CO
 
1.3
 
7
 
100%
 
Piceance
Northeast
 
 
 
 
 
 
 
 
 
Fort Beeler
Marshall County, WV
 
0.5
 
62
 
100%
 
Appalachian
Atlantic-Gulf
 
 
 
 
 
 
 
 
 
Markham
Markham, TX
 
0.5
 
45
 
100%
 
Western Gulf of Mexico
Mobile Bay
Coden, AL
 
0.7
 
30
 
100%
 
Eastern Gulf of Mexico
Discovery (1)
Larose, LA
 
0.6
 
32
 
60%
 
Central Gulf of Mexico

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__________
(1)
Statistics reflect 100 percent of the assets from the jointly owned investment that we operate; however, our financial statements report equity method income from this investment based on our equity ownership percentage.
Crude Oil Transportation and Production Handling Assets
In addition to our natural gas assets, we own and operate four deepwater crude oil pipelines and own production platforms serving the deepwater in the Gulf of Mexico. Our crude oil transportation revenues are typically volumetric-based fee arrangements. However, a portion of our marketing revenues are recognized from purchase and sale arrangements whereby the oil that we transport is purchased and sold as a function of the same index-based price. Our offshore floating production platforms provide centralized services to deepwater producers such as compression, separation, production handling, water removal, and pipeline landings. Revenue sources have historically included a combination of fixed-fee, volumetric-based fee and cost reimbursement arrangements. Fixed fees associated with the resident production at our Devils Tower facility are recognized on a units-of-production basis.
The following tables summarize our significant crude oil transportation pipelines and production handling platforms as of December 31, 2013:
 
Crude Oil Pipelines
 
Pipeline
Miles
 
Capacity
(Mbbls/d)
 
Ownership
Interest
 
Supply Basins
Mountaineer & Blind Faith
155
 
150
 
100%
 
Eastern Gulf of Mexico
BANJO
57
 
90
 
100%
 
Western Gulf of Mexico
Alpine
96
 
85
 
100%
 
Western Gulf of Mexico
Perdido Norte
74
 
150
 
100%
 
Western Gulf of Mexico
 
Production Handling Platforms
 
Gas Inlet
Capacity
(MMcf/d)
 
Crude/NGL
Handling
Capacity
(Mbbls/d)
 
Ownership
Interest
 
Supply Basins
Devils Tower
210
 
60
 
100%
 
Eastern Gulf of Mexico
Discovery Grand Isle 115 (1)
150
 
10
 
60%
 
Central Gulf of Mexico
___________
(1)
Statistics reflect 100 percent of the assets from the jointly owned investment that we operate; however, our financial statements report equity method income from this investment based on our equity ownership percentage.

Gulf Olefins
WPZ has an 83.3 percent undivided interest and operatorship of the olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter, and pipelines in the Gulf region. Our olefins business also operates an ethylene storage hub at Mont Belvieu using leased third-party underground storage caverns.
Our olefins production facility has a total production capacity of 1.35 billion pounds of ethylene and 90 million pounds of propylene per year. Our feedstocks for the cracker are ethane and propane; as a result, these assets are primarily exposed to the price spread between ethane and propane, and ethylene and propylene, respectively. Ethane and propane are available for purchase from third parties and from affiliates. We own ethane and propane pipeline systems in Louisiana that provide feedstock transportation to the Geismar plant and other third-party crackers. We also own a pipeline that has the capacity to supply 12 Mbbls/d of ethane from Discovery’s Paradis fractionator to the Geismar plant.

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

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Our refinery grade propylene splitter has a production capacity of approximately 500 million pounds per year of propylene. At our propylene splitter, we purchase refinery grade propylene and fractionate it into polymer grade propylene and propane; as a result, this asset is exposed to the price spread between those commodities.
As a merchant producer of ethylene and propylene, our product sales are to customers for use in making plastics and other downstream petrochemical products destined for both domestic and export markets.
Marketing Services
We market NGL products to a wide range of users in the energy and petrochemical industries. The NGL marketing business transports and markets our equity NGLs from the production at our processing plants, and also markets NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers, and the NGL volumes owned by Discovery. The NGL marketing business bears the risk of price changes in these NGL volumes while they are being transported to final sales delivery points. In order to meet sales contract obligations, we may purchase products in the spot market for resale. Other than a long-term agreement to sell our equity NGLs transported on OPPL to ONEOK Hydrocarbon L.P., the majority of sales are based on supply contracts of one year or less in duration. Sales to ONEOK Hydrocarbon L.P., accounted for 9 percent, 14 percent, and 17 percent of our consolidated revenues in 2013, 2012, and 2011, respectively.
In certain situations to facilitate our gas gathering and processing activities, we buy natural gas from our producer customers for resale.
We also market olefin products to a wide range of users in the energy and petrochemical industries. In order to meet sales contract obligations, we may purchase olefin products for resale.
Other NGL & Petchem Operations
We own interests in and/or operate NGL fractionation and storage assets. These assets include a 50 percent interest in an NGL fractionation facility near Conway, Kansas, with capacity of slightly more than 100 Mbbls/d and a 31.5 percent interest in another fractionation facility in Baton Rouge, Louisiana, with a capacity of 60 Mbbls/d. We also own approximately 20 million barrels of NGL storage capacity in central Kansas near Conway.
We own approximately 170 miles of pipelines in the Houston Ship Channel area which transport a variety of products including ethane, propane, ammonia, tertiary butyl alcohol, and other industrial products used in the petrochemical industry. We also own a tunnel crossing pipeline under the Houston Ship Channel which contains multiple pipelines which are leased to third parties.
We also own a 14.6 percent equity interest in Aux Sable and its Channahon, Illinois, gas processing and NGL fractionation facility near Chicago. The facility is capable of processing up to 2.1 Bcf/d of natural gas from the Alliance Pipeline system and fractionating approximately 102 Mbbls/d of extracted liquids into NGL products. Additionally, Aux Sable owns an 80 MMcf/d gas conditioning plant and a 12-inch, 83-mile gas pipeline infrastructure in North Dakota that provides additional NGLs to Channahon from the Bakken Shale in the Williston basin.
WPZ Operating Areas
WPZ organizes these businesses into the following operating areas:
Northeast G&P is comprised of the midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 51 percent equity investment in Laurel Mountain and a 47.5 percent equity investment in Caiman II.
Atlantic-Gulf is comprised of Transco and significant natural gas gathering and processing and crude production handling and transportation in the Gulf Coast region, as well as a 50 percent equity investment in Gulfstream, a 41 percent interest in Constitution (a consolidated entity), and a 60 percent equity investment in Discovery.
West is comprised of the gathering, processing and treating operations in New Mexico, Colorado, and Wyoming and Northwest Pipeline.

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NGL & Petchem Services is comprised of the energy commodities marketing business, an NGL fractionator and storage facilities near Conway, Kansas, a 50 percent equity investment in OPPL, and an 83.3 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf Coast region.
Operated Equity Investments
Discovery
We own a 60 percent equity interest in and operate the facilities of Discovery. Discovery’s assets include a 600
MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 32 Mbbls/d NGL fractionator plant near Paradis, Louisiana, and an offshore natural gas gathering and transportation system in the Gulf of Mexico. Construction is in progress for the Keathley Canyon Connector, a deepwater lateral pipeline in the central deepwater Gulf of Mexico. The lateral pipeline is estimated to have the capacity to flow more than 400 MMcf/d and will accommodate the tie-in of other deepwater prospects.
Laurel Mountain
We own a 51 percent equity interest in a joint venture, Laurel Mountain, that includes a gathering system that we operate in western Pennsylvania. Laurel Mountain has a long-term, dedicated, volumetric-based fee agreement, with exposure to natural gas prices, to gather the anchor customer’s production in the western Pennsylvania area of the Marcellus Shale.
Overland Pass Pipeline
We also operate and own a 50 percent ownership interest in OPPL. OPPL is capable of transporting 255 Mbbls/d and includes approximately 1,096 miles of NGL pipeline extending from Opal, Wyoming, to the Mid-Continent NGL market center near Conway, Kansas, along with extensions into the Piceance and Denver-Julesberg basins in Colorado. In 2013, a pipeline connection and capacity expansions were installed to accommodate volumes coming from the Bakken Shale in the Williston basin in North Dakota. Our equity NGL volumes from our two Wyoming plants and our Willow Creek facility in Colorado are dedicated for transport on OPPL under a long-term transportation agreement.
Operating Statistics
The following table summarizes our significant operating statistics for Williams Partners’ midstream business:

2013

2012

2011
Volumes: (1)





Gathering (Tbtu)
1,731


1,616


1,377

Plant inlet natural gas (Tbtu)
1,549


1,638


1,592

NGL production (Mbbls/d) (2)
143


209


189

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


77


77

Crude oil transportation (Mbbls/d) (2)
117


126


105

Geismar ethylene sales (millions of pounds)
467


1,058


1,038

__________
(1)
Excludes volumes associated with Partially Owned Entities.
(2)
Annual average Mbbls/d.
Williams NGL & Petchem Services
The Williams NGL & Petchem Services segment consists primarily of our Canadian midstream business, certain domestic olefins pipeline assets, and the proposed Bluegrass Pipeline, a new joint project which would connect processing facilities in the Marcellus and Utica shale-gas areas in the U.S. Northeast to growing petrochemical and export markets in the U.S. Gulf Coast.

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

The Fort McMurray extraction plant has processing capacity of 121 MMcf/d with the ability to recover in excess of 26 Mbbls/d of olefin and NGL products. Our Redwater fractionator has a liquids handling capacity of 26 Mbbls/d. The B/B Splitter, which has a production capacity of 3.7 Mbbls/d of butylene and 3.7 Mbbls/d of butane, further fractionates the butylene/butane mix produced at our Redwater fractionators into separate butylene and butane products, which receive higher values and are in greater demand. We also purchase small volumes of olefin/NGLs mixes from third-party gas processors, fractionate the olefins and NGLs at our Redwater plant and sell the resulting products. The Boreal Pipeline is a 261-mile pipeline in Canada that transports recovered NGLs and olefins from our extraction plant in Fort McMurray to our Redwater fractionation facility. The pipeline has an initial capacity of 43 Mbbls/d that can be increased to an ultimate capacity of 125 Mbbls/d with additional pump stations. Our products are sold within Canada and the United States.
In the second quarter of 2013, we formed a joint project to develop the Bluegrass Pipeline. We own a 50 percent interest in Bluegrass Pipeline (a consolidated entity). The proposed pipeline would deliver mixed NGLs from these producing areas to proposed new fractionation and storage facilities, which would have connectivity to petrochemical facilities and product pipelines along the coasts of Louisiana and Texas. We are in discussions with potential customers regarding commitments to the pipeline. Completion of this project is subject to all necessary or required approvals, elections, and actions, as well as execution of formal customer commitments. We currently estimate the Bluegrass Pipeline will be in-service in mid-to-late 2016.
Operating Statistics
The following table summarizes our significant operating statistics:
 
2013
 
2012
 
2011
Volumes:
 
 
 
 
 
Canadian propylene sales (millions of pounds)
118

 
153

 
139

Canadian NGL sales (millions of gallons)
172

 
165

 
163

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

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The following table summarizes ACMP’s average daily throughput and assets by region as of and for the year ended December 31, 2013:
 
 
 
Location
 
Average Throughput (Bcf/d) (1)
 
Approximate Length of Pipeline (Miles)
 
Gas Compression (Horsepower)
Region
 
 
 
 
 
 
 
Barnett Shale
Texas
 
1.045
 
859
 
150,945
Eagle Ford Shale
Texas
 
0.263
 
870
 
93,847
Haynesville Shale
Louisiana
 
0.669
 
582
 
20,195
Marcellus Shale
Pennsylvania & West Virginia
 
1.019
 
823
 
136,090
Niobrara Shale
Wyoming
 
0.015
 
132
 
15,665
Utica Shale
Ohio
 
0.107
 
265
 
63,505
Mid-Continent
Texas, Oklahoma, Kansas, & Arkansas
 
0.581
 
2,805
 
108,735
       Total
 
 
3.699
 
6,336
 
588,982
__________
(1)
Throughput in all regions represents net throughput allocated to ACMP’s Partnership interest.
Additional Business Segment Information
Our ongoing business segments are presented as continuing operations in the accompanying financial statements and Notes to Consolidated Financial Statements included in Part II.
We perform certain management, legal, financial, tax, consultation, information technology, administrative and other services for our subsidiaries.
Our principal sources of cash are from dividends, distributions and advances from our subsidiaries, investments, payments by subsidiaries for services rendered, and, if needed, external financings, and net proceeds from asset sales. The terms of certain subsidiaries’ borrowing arrangements may limit the transfer of funds to us under certain conditions.
We believe that we have adequate sources and availability of raw materials and commodities for existing and anticipated business needs. Our interstate pipeline systems are all regulated in various ways resulting in the financial return on the investments made in the systems being limited to standards permitted by the regulatory agencies. Each of the pipeline systems has ongoing capital requirements for efficiency and mandatory improvements, with expansion opportunities also necessitating periodic capital outlays.
Revenues by service that exceeded 10 percent of consolidated revenue include:
 
2013
 
2012
 
2011

(Millions)
Service:
 
 
 
 
 
Regulated natural gas transportation and storage
$
1,713

 
$
1,609

 
$
1,569

Gathering & processing
932

 
844

 
703



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REGULATORY MATTERS
Williams Partners
FERC
Williams Partners’ gas pipeline interstate transmission and storage activities are subject to FERC regulation under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978, and, as such, its rates and charges for the transportation of natural gas in interstate commerce, its accounting, and the extension, enlargement or abandonment of its jurisdictional facilities, among other things, are subject to regulation. Each gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. FERC Standards of Conduct govern how our interstate pipelines communicate and do business with gas marketing employees. Among other things, the Standards of Conduct require that interstate pipelines not operate their systems to preferentially benefit gas marketing functions.
FERC regulation requires all terms and conditions of service, including the rates charged, to be filed with and approved by the FERC before any changes can go into effect. Each of our interstate natural gas pipeline companies establishes its rates primarily through the FERC’s ratemaking process. Key determinants in the ratemaking process are:
•
Costs of providing service, including depreciation expense;
•
Allowed rate of return, including the equity component of the capital structure and related income taxes;
•
Contract and volume throughput assumptions.
The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues previously collected may be subject to refund.
Williams Partners also owns interests in and operates two offshore transmission pipelines that are regulated by the FERC because they are deemed to transport gas in interstate commerce. Black Marlin Pipeline Company provides transportation service for offshore Texas production in the High Island area and redelivers that gas to intrastate pipeline interconnects near Texas City. Discovery provides transportation service for offshore Louisiana production from the South Timbalier, Grand Isle, Ewing Bank, and Green Canyon (deepwater) areas to an onshore processing facility and downstream interconnect points with major interstate pipelines. In addition, Williams Partners owns a 50 percent interest in, and is the operator of OPPL, which is an interstate natural gas liquids pipeline regulated by the FERC pursuant to the Interstate Commerce Act. OPPL provides transportation service pursuant to tariffs filed with the FERC.
Pipeline Safety
Williams Partners’ gas pipelines are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, and the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety Act), which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. The United States Department of Transportation (USDOT) administers federal pipeline safety laws.
Federal pipeline safety laws authorize USDOT to establish minimum safety standards for pipeline facilities and persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce. USDOT has also established reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, USDOT performs pipeline safety inspections and has the authority to initiate enforcement actions.

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Federal pipeline safety regulations contain an exemption that applies to gathering lines in certain rural locations. A substantial portion of our gathering lines qualify for that exemption and are currently not regulated under federal law. However, USDOT is completing a congressionally-mandated review of the adequacy of the existing federal and state regulations for gathering lines and has indicated that it may apply additional safety standards to rural gas gathering lines in the future.
States are preempted by federal law from regulating pipeline safety for interstate pipelines but most are certified by USDOT to assume responsibility for enforcing intrastate pipeline safety regulations and inspecting intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, they vary considerably in their authority and capacity to address pipeline safety.
On January 3, 2012, the Pipeline Safety Act was enacted. The Pipeline Safety Act requires USDOT to complete a number of reports in preparation for potential rulemakings. The issues addressed in these rulemaking provisions include, but are not limited to, the use of automatic or remotely controlled shut-off valves on new or replaced transmission line facilities, modifying the requirements for pipeline leak detection systems, and expanding the scope of the pipeline integrity management requirements. USDOT is considering these and other provisions in the Pipeline Safety Act and has sought public comment on changes to the standards in its pipeline safety regulations.
Pipeline Integrity Regulations
We have developed an enterprise wide Gas Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for gas transmission pipelines that could affect high consequence areas in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments to be completed within required time frames. In meeting the integrity regulations, we have identified high consequence areas and developed baseline assessment plans. We completed the assessments within the required time frames, with one exception which was reported to PHMSA. Ongoing periodic reassessments and initial assessments of any new high consequence areas are expected to be completed within the time frames required by the rule. We estimate that the cost to be incurred in 2014 associated with this program to be approximately $43 million, most of which we expect to be capital expenditures. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through Northwest Pipeline’s and Transco’s rates.
We developed a Liquid Integrity Management Plan that we believe meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires liquid pipeline operators to develop an integrity management program for liquid transmission pipelines that could affect high consequence areas (whether onshore or offshore) in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments expected to be completed within required time frames. In meeting the integrity regulations, we utilized government defined high consequence areas and developed baseline assessment plans. We completed assessments within the required time frames. We estimate that the cost to complete the remediation associated with the 2013 assessments will be approximately $100,000, most of which we expect to be included in 2014 operating expenses. Ongoing periodic reassessments and initial assessments of any new high consequence areas are expected to be completed within the time frames required by the rule. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business.
State Gathering Regulation
Our onshore midstream gathering operations are subject to regulation by states in which we operate. Of the states where our midstream business gathers gas, currently only Texas actively regulates gathering activities. Texas regulates gathering primarily through complaint mechanisms under which the state commission may resolve disputes involving an individual gathering arrangement.

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OCSLA
Our offshore midstream gathering is subject to the Outer Continental Shelf Lands Act (OCSLA). Although offshore gathering facilities are not subject to the NGA, offshore transmission pipelines are subject to the NGA, and in recent years the FERC has taken a broad view of offshore transmission, finding many shallow-water pipelines to be jurisdictional transmission. Most offshore gathering facilities are subject to the OCSLA, which provides in part that outer continental shelf pipelines “must provide open and nondiscriminatory access to both owner and nonowner shippers.”
Olefins
Williams Partners’ olefins assets are regulated by the Louisiana Department of Environmental Quality, the Texas Railroad Commission, and various other state and federal entities regarding our liquids pipelines.
These olefins assets are also subject to the liquid pipeline safety and integrity regulations previously discussed above since both Louisiana and Texas have adopted the integrity management regulations defined by PHMSA.

Williams NGL & Petchem Services

Our Canadian assets are regulated by the Alberta Energy Regulator (“AER”), which includes specifics to pipeline safety and integrity. The regulatory system for the Alberta oil and gas industry incorporates a large measure of self-regulation, providing that licensed operators are held responsible for ensuring that their operations are conducted in accordance with all provincial regulatory requirements. For situations in which noncompliance with the applicable regulations is at issue, the AER has an enforcement process with escalating consequences.
See Note 17 – Contingent Liabilities and Commitments of our Notes to Consolidated Financial Statements for further details on our regulatory matters.
ENVIRONMENTAL MATTERS
Our operations are subject to federal environmental laws and regulations as well as the state, local and tribal laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil, or water, as well as liability for cleanup costs. Materials could be released into the environment in several ways including, but not limited to:
•
Leakage from gathering systems, underground gas storage caverns, pipelines, processing or treating facilities, transportation facilities and storage tanks;
•
Damage to facilities resulting from accidents during normal operations;
•
Damages to onshore and offshore equipment and facilities resulting from storm events or natural disasters;
•
Blowouts, cratering and explosions.
In addition, we may be liable for environmental damage caused by former owners or operators of our properties.
We believe compliance with current environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings or current competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, fines and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses.
For additional information regarding the potential impact of federal, state, tribal or local regulatory measures on our business and specific environmental issues, please refer to “Risk Factors — “Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities and expenditures and could exceed current expectations,”

17



and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental” and “Environmental Matters” in Note 17 – Contingent Liabilities and Commitments of our Notes to Consolidated Financial Statements.
COMPETITION
Williams Partners
For Williams Partners’ gas pipeline business, the natural gas industry has undergone significant change over the past two decades. A highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. More recently large reserves of shale gas have been discovered, in many cases much closer to major market centers. As a result, pipeline capacity is being used more efficiently and competition among pipeline suppliers to connect growing supply to market has increased.
Local distribution company (LDC) and electric industry restructuring by states have affected pipeline markets. Pipeline operators are increasingly challenged to accommodate the flexibility demanded by customers and allowed under tariffs. The state plans have in some cases discouraged LDCs from signing long-term contracts for new capacity.
States have developed new plans that require utilities to encourage energy saving measures and diversify their energy supplies to include renewable sources. This has lowered the growth of residential gas demand. However, due to relatively low prices of natural gas, demand for electric power generation has increased.
These factors have increased the risk that customers will reduce their contractual commitments for pipeline capacity from traditional producing areas. Future utilization of pipeline capacity will depend on these factors and others impacting both U.S. and global demand for natural gas.
In Williams Partners’ midstream business, we face regional competition with varying competitive factors in each basin. Our gathering and processing business competes with other midstream companies, interstate and intrastate pipelines, producers and independent gatherers and processors. We primarily compete with five to ten companies across all basins in which we provide services. Numerous factors impact any given customer’s choice of a gathering or processing services provider, including rate, location, term, reliability, timeliness of services to be provided, pressure obligations and contract structure. We also compete in recruiting and retaining skilled employees.
Ethylene and propylene markets, and therefore Williams Partners’ olefins business, compete in a worldwide marketplace. Due to our NGL feedstock position at Geismar, we expect to benefit from the lower cost position in North America versus other crude based feedstocks worldwide. The majority of North American olefins producers have significant downstream petrochemical manufacturing for plastics and other products. As such, they buy or sell ethylene and propylene as required. We operate as a merchant seller of olefins with no downstream manufacturing, and therefore can be either a supplier or a competitor at any given time to these other companies. We compete on the basis of service, price and availability of the products we produce.
Williams NGL & Petchem Services
Our Canadian midstream facilities continue to be the only NGL/olefins fractionator in western Canada and the only processor of oil sands upgrader offgas. Our extraction of liquids from the upgrader offgas stream allows the upgraders to burn cleaner natural gas streams and reduce their overall air emissions. Our Canadian midstream business competes for the sale of its products with traditional Canadian midstream companies on the basis of operational expertise, price, service offerings and availability of the products we produce.

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

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 February 1, 2014, we had approximately 4,909 full-time employees.
FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS
See Note 18 – Segment Disclosures of our Notes to Consolidated Financial Statements for amounts of revenues during the last three fiscal years from external customers attributable to the United States and all foreign countries. Also see Note 18 – Segment Disclosures of our Notes to Consolidated Financial Statements for information relating to long-lived assets during the last three fiscal years, located in the United States and all foreign countries.

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Item 1A. Risk Factors
FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT
FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,”“in service date,” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
•
Amounts and nature of future capital expenditures;
•
Expansion and growth of our business and operations;
•
Financial condition and liquidity;
•
Business strategy;
•
Cash flow from operations or results of operations;
•
The levels of dividends to stockholders;
•
Natural gas, natural gas liquids and olefins supply, prices and demand;
•
Demand for our services.
Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:
•
Whether we have sufficient cash to enable us to pay current and expected levels of dividends;
•
Availability of supplies, market demand, and volatility of prices;
•
Inflation, interest rates, fluctuation in foreign exchange rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
•
The strength and financial resources of our competitors and the effects of competition;
•
Whether we are able to successfully identify, evaluate and execute investment opportunities;

20



•
Ability to acquire new businesses and assets and successfully integrate those operations and assets into our existing businesses, as well as successfully expand our facilities;
•
Development of alternative energy sources;
•
The impact of operational and development hazards and unforeseen interruptions;
•
Costs of, changes in, or the results of laws, government regulations (including safety and environmental regulations), environmental liabilities, litigation, and rate proceedings;
•
Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
•
Changes in maintenance and construction costs;
•
Changes in the current geopolitical situation;
•
Our exposure to the credit risk of our customers and counterparties;
•
Risks related to financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of capital;
•
The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;
•
Risks associated with weather and natural phenomena, including climate conditions;
•
Acts of terrorism, including cybersecurity threats and related disruptions;
•
Additional risks described in our filings with the SEC.
Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section.
RISK FACTORS
You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, operating results, and financial condition, as well as adversely affect the value of an investment in our securities.
Prices for NGLs, olefins, natural gas, oil and other commodities, are volatile and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain our existing businesses.
Our revenues, operating results, future rate of growth and the value of certain components of our businesses depend primarily upon the prices of NGLs, olefins, natural gas, oil or other commodities, and the differences between prices

21



of these commodities. Price volatility can impact both the amount we receive for our products and services and the volume of products and services we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Price volatility can also have an adverse effect on our business, results of operations, financial condition and cash flows.
The markets for NGLs, olefins, natural gas, oil and other commodities are likely to continue to be volatile. Wide fluctuations in prices might result from one or more factors beyond our control, including:
•
Worldwide and domestic supplies of and demand for natural gas, NGLs, olefins, oil, and related commodities;
•
Turmoil in the Middle East and other producing regions;
•
The activities of the Organization of Petroleum Exporting Countries;
•
The level of consumer demand;
•
The price and availability of other types of fuels or feedstocks;
•
The availability of pipeline capacity;
•
Supply disruptions, including plant outages and transportation disruptions;
•
The price and quantity of foreign imports of natural gas and oil;
•
Domestic and foreign governmental regulations and taxes;
•
The credit of participants in the markets where products are bought and sold.
The long-term financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access, and demand for those supplies in our traditional markets.
Our ability to maintain and expand our natural gas transportation and midstream businesses depends on the level of drilling and production by third parties in our supply basins. Production from existing wells and natural gas supply basins with access to our pipeline and gathering systems will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. In addition, low prices for natural gas, regulatory limitations, or the lack of available capital could adversely affect the development and production of additional natural gas reserves, the installation of gathering, storage, and pipeline transportation facilities and the import and export of natural gas supplies. The competition for natural gas supplies to serve other markets could also reduce the amount of natural gas supply for our customers. A failure to obtain access to sufficient natural gas supplies will adversely impact our ability to maximize the capacities of our gathering, transportation and processing facilities.
Demand for our services is dependent on the demand for gas in the markets we serve. Alternative fuel sources such as electricity, coal, fuel oils or nuclear energy could reduce demand for natural gas in our markets and have an adverse effect on our business.
A failure to obtain access to sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could result in impairments of our assets and have a material adverse effect on our business, financial condition and results of operations.
We may not be able to grow or effectively manage our growth.
As part of our growth strategy, we consider acquisition opportunities and engage in significant capital projects. We recently implemented our project lifecycle process and refocused our investment evaluation process. These are processes we use to identify, evaluate and execute on acquisition opportunities and capital projects. We may not always

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have sufficient and accurate information to identify and value potential opportunities and risks or our investment evaluation process may be incomplete or flawed. Regarding potential acquisitions, suitable acquisition candidates may not be available on terms and conditions we find acceptable or, where multiple parties are trying to acquire an acquisition candidate, we may not be chosen as the acquirer. If we are able to acquire a targeted business, we may not be able to successfully integrate the acquired businesses and realize anticipated benefits in a timely manner. Our growth may also be dependent upon the construction of new natural gas gathering, transportation, compression, processing or treating pipelines and facilities, NGL transportation, fractionation or storage facilities or olefins processing facilities, as well as the expansion of existing facilities. We also face all the risks associated with construction. These risks include the inability to obtain skilled labor, equipment, materials, permits, rights-of-way and other required inputs in a timely manner such that projects are completed on time and the risk that construction cost overruns could cause total project costs to exceed budgeted costs. Additional risks associated with growing our business include, among others, that:
•
Changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings and cash flow relating to potential investment targets, resulting in outcomes which are materially different than anticipated;
•
We could be required to contribute additional capital to support acquired businesses or assets. We may assume liabilities that were not disclosed to us, that exceed our estimates and for which contractual protections are either unavailable or prove inadequate;
•
Acquisitions could disrupt our ongoing business, distract management, divert financial and operational resources from existing operations and make it difficult to maintain our current business standards, controls and procedures;
•
Acquisitions and capital projects may require substantial new capital, either by the issuance of debt or equity, and we may not be able to access capital markets or obtain acceptable terms.
If realized, any of these risks could have an adverse impact on our results of operations, including the possible impairment of our assets, and could also have an adverse impact on our financial position or cash flows.
We do not own all of the interests in the Partially Owned Entities, which could adversely affect our ability to operate and control these assets in a manner beneficial to us.
Because we do not control the Partially Owned Entities, we may have limited flexibility to control the operation of or cash distributions received from these entities. The Partially Owned Entities’ organizational documents require distribution of their available cash to their members on a quarterly basis; however, in each case, available cash is reduced, in part, by reserves appropriate for operating the businesses. At December 31, 2013, our investments in the Partially Owned Entities accounted for approximately 16 percent of our total consolidated assets. Conflicts of interest may arise in the future between us, on the one hand, and our Partially Owned Entities, on the other hand, with regard to our Partially Owned Entities’ governance, business and operations. If a conflict of interest arises between us and a Partially Owned Entity, other owners may control the Partially Owned Entity’s actions with respect to such matter (subject to certain limitations), which could be detrimental to our business. Any future disagreements with the other co-owners of these assets could adversely affect our ability to respond to changing economic or industry conditions, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.  
Holders of our common stock may not receive dividends in the amount identified in guidance or any dividends.

We may not have sufficient cash flow each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash we dividend will depend on various factors, some of which are beyond our control, including:
•
The amount of cash that WPZ, our other subsidiaries and the Partially Owned Entities distribute to us;
•
The amount of cash we generate from our operations, our working capital needs, our level of capital expenditures, and our ability to borrow;

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•
The restrictions contained in our indentures and credit facility and our debt service requirements;
•
The cost of acquisitions, if any.
A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage and a decrease in the value of our stock price.
Our cash flow depends heavily on the earnings and distributions of WPZ.
Our partnership interest, including the general partner’s holding of incentive distribution rights, in WPZ is our largest cash-generating asset. Therefore, our cash flow is heavily dependent upon the ability of WPZ to make distributions to its partners. A significant decline in WPZ’s earnings and/or distributions would have a corresponding negative impact on us.
Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.
We have numerous competitors in all aspects of our businesses, and additional competitors may enter our markets. Some of our competitors are large oil, natural gas and petrochemical companies that have greater access to supplies of natural gas and NGLs than we do. In addition, current or potential competitors may make strategic acquisitions or have greater financial resources than we do, which could affect our ability to make strategic investments or acquisitions. Our competitors may be able to respond more quickly to new laws or regulations or emerging technologies or to devote greater resources to the construction, expansion or refurbishment of their facilities than we can. Similarly, a highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. Failure to successfully compete against current and future competitors could have a material adverse effect on our business, results of operations, financial condition and cash flows.
We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay dividends, and our ability to grow.
We rely on a limited number of customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. Although many of our customers and suppliers are subject to long-term contracts, if we are unable to replace or extend such contracts or add additional customers, each on favorable terms, if at all, our financial condition, growth plans, and the amount of cash available to pay distributions could be adversely affected. Our ability to replace, extend, or add additional customer or supplier contracts on favorable terms, or at all, is subject to a number of factors, some of which are beyond our control, including:
•
The level of existing and new competition in our businesses or from alternative fuel sources, such as electricity, coal, fuel oils, or nuclear energy;
•
Natural gas, NGL, and olefins prices, demand, availability and margins in our markets. Higher prices for energy commodities related to our businesses could result in a decline in the demand for those commodities and, therefore, in customer contracts or throughput on our pipeline systems. Also, lower energy commodity prices could result in a decline in the production of energy commodities resulting in reduced customer contracts, supply contracts, and throughput on our pipeline systems;
•
General economic, financial markets and industry conditions;
•
The effects of regulation on us, our customers and our contracting practices;

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•
Our ability to understand our customers’ expectations, efficiently and reliably deliver high quality services and effectively manage customer relationships. The results of these efforts will impact our reputation and positioning in the market.
Our operations are subject to operational hazards and unforeseen interruptions.
There are operational risks associated with the gathering, transporting, storage, processing and treating of natural gas, the fractionation, transportation and storage of NGLs, processing of olefins, and crude oil transportation and production handling, including:
•
Aging infrastructure and mechanical problems;
•
Damages to pipelines and pipeline blockages or other pipeline interruptions;
•
Uncontrolled releases of natural gas (including sour gas), NGLs, brine or industrial chemicals;
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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;
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Fires, explosions, craterings and blowouts;
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Truck and rail loading and unloading;
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Operating in a marine environment.
Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, loss of services to our customers, reputational damage and substantial losses to us. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. An event such as those described above could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.
We do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.
In accordance with customary industry practice, we maintain insurance against some, but not all, risks and losses, and only at levels we believe to be appropriate. We currently maintain excess liability insurance with limits of $610 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers us, our subsidiaries, and certain of our affiliates for legal and contractual liabilities arising out of bodily injury or property damage, including resulting loss of use to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and NGL operations.
Although we maintain property insurance on certain physical assets that we own, lease or are responsible to insure, the policy may not cover the full replacement cost of all damaged assets or the entire amount of business interruption loss we may experience. In addition, certain perils may be excluded from coverage or be sub-limited. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. We may elect to self insure a portion of our risks. We do not insure our onshore underground pipelines for physical damage, except at certain locations such as river crossings and compressor stations. Offshore assets are covered for property damage when loss

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is due to a named windstorm event, but coverage for loss caused by a named windstorm is significantly sub-limited and subject to a large deductible. All of our insurance is subject to deductibles.
In addition, to the insurance coverage described above, we are a member of Oil Insurance Limited (OIL), an energy industry mutual insurance company, which provides coverage for damage to our property. As an insured member of OIL, we share in the losses among other OIL members even if our property is not damaged.
The occurrence of any risks not fully covered by insurance could have a material adverse effect on our business, results of operations, financial condition, cash flows and our ability to repay our debt.
The time required to return WPZ’s Geismar olefins plant to operation following the explosion and fire at the facility on June 13, 2013, and the extent and timing of costs and insurance recoveries related to the incident could be materially different than we anticipate and could cause our financial results and levels of dividends to be materially different than we project.
Our projections of financial results and expected levels of dividends are based on numerous assumptions and estimates, including but not limited to the time required to return WPZ’s Geismar, Louisiana, olefins plant to operation and complete the expansion project at the facility following the explosion and fire at the plant on June 13, 2013, and the extent and timing of costs and insurance recoveries related to the incident. Our financial results and levels of dividends could be materially different than we project if our assumptions and estimates related to the incident are materially different than actual outcomes.
Our assets and operations, as well as our customers’ assets and operations, can be adversely affected by weather and other natural phenomena.
Our assets and operations, especially those located offshore, and our customers’ assets and operations can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes, fires and other natural phenomena and weather conditions, including extreme or unseasonable temperatures, making it more difficult for us to realize the historic rates of return associated with our assets and operations. A significant disruption in our or our customers’ operations or a significant liability for which we are not fully insured could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Acts of terrorism could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Given the volatile nature of the commodities we transport, process, store and sell, our assets and the assets of our customers and others in our industry may be targets of terrorist activities. A terrorist attack could create significant price volatility, disrupt our business, limit our access to capital markets or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport or distribute natural gas, NGLs or other commodities. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.
We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. While we believe that we maintain appropriate information security policies, practices and protocols, we face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational industrial control systems and safety systems that operate our pipelines, plants and assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists,” or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. We

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could also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information.
Breaches in our information technology infrastructure or physical facilities, or other disruptions including those arising from theft, vandalism, fraud or unethical conduct, could result in damage to our assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.
The natural gas sales, transportation and storage operations of our gas pipelines are subject to regulation by the FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines, including a reasonable rate of return.
In addition to regulation by other federal, state and local regulatory authorities, under the Natural Gas Act of 1938, interstate pipeline transportation and storage service is subject to regulation by the FERC. Federal regulation extends to such matters as:
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Transportation and sale for resale of natural gas in interstate commerce;
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Rates, operating terms, types of services and conditions of service;
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Certification and construction of new interstate pipelines and storage facilities;
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Acquisition, extension, disposition or abandonment of existing interstate pipelines and storage facilities;
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Accounts and records;
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Depreciation and amortization policies;
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Relationships with affiliated companies who are involved in marketing functions of the natural gas business;
•
Market manipulation in connection with interstate sales, purchases or transportation of natural gas.
Regulatory or administrative actions in these areas, including successful complaints or protests against rates of the gas pipelines, can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs and otherwise altering the profitability of our pipeline business.
Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities and expenditures that could exceed expectations.
Our operations are subject to extensive federal, state, tribal and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment and the security of chemical and industrial facilities. Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, storage, processing and treating of natural gas, fractionation, transportation and storage of NGLs, processing of olefins, and crude oil transportation and production handling as well as waste disposal practices. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations and delays in granting permits.
Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil and wastes on, under or from our properties and facilities. Private parties, including the owners of properties through which our pipeline and gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages

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for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours.
We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
In addition, climate change regulations and the costs associated with the regulation of emissions of greenhouse gases (GHGs) have the potential to affect our business. Regulatory actions by the EPA or the passage of new climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage our GHG compliance program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Climate change and GHG regulation could also reduce demand for our services.
If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues could be adversely affected.
We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Because we do not own these third-party pipelines or other facilities, their continuing operation is not within our control. If these pipelines or facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or other causes, we and our customers would have reduced capacity to transport, store or deliver natural gas or NGL products to end use markets or to receive deliveries of mixed NGLs, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect or in operations on third-party pipelines or facilities that would cause a material reduction in volumes transported on our pipelines or our gathering systems or processed, fractionated, treated or stored at our facilities could have a material adverse effect on our business, results of operations, financial condition and cash flows.
Legal and regulatory proceedings and investigations relating to the energy industry have adversely affected our business and may continue to do so. The operation of our businesses might also be adversely affected by changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.
Public and regulatory scrutiny of the energy industry has resulted in the proposal and/or implementation of increased regulations. Such scrutiny has also resulted in various inquiries, investigations and court proceedings, including litigation of energy industry matters. Both the shippers on our pipelines and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.
Certain inquiries, investigations and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines and/or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our results of operations or increase our operating costs in other ways. Current legal proceedings or other matters, including environmental matters, suits, regulatory appeals and similar matters might result in adverse decisions against us which, among other outcomes, could result in the imposition of substantial penalties and fines and could

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damage our reputation. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.
In addition, existing regulations might be revised or reinterpreted, and new laws and regulations might be adopted or become applicable to us, our facilities or our customers. If new laws or regulations are imposed relating to oil and gas extraction, or if additional levels of reporting, regulation or permitting moratoria are required or imposed, including those related to hydraulic fracturing, the volumes of natural gas and other products that we transport, gather, process and treat could decline and our results of operations could be adversely affected.
Certain of our gas pipeline services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.
Our gas pipelines provide some services pursuant to long-term, fixed price contracts. It is possible that costs to perform services under such contracts will exceed the revenues our pipelines collect for their services. Although most of the services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.
Our operating results for certain components of our business might fluctuate on a seasonal basis.
Revenues from certain components of our business can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and pipeline systems and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. In those instances in which we do not own the land on which our facilities are located, we obtain the rights to construct and operate our pipelines and gathering systems on land owned by third parties and governmental agencies for a specific period of time. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited term. We may not have the right of eminent domain over land owned by Native American tribes. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and cash flows.
Difficult conditions in the global financial markets and the economy in general could negatively affect our business and results of operations.
Our businesses may be negatively impacted by adverse economic conditions or future disruptions in global financial markets. Included among these potential negative impacts are industrial or economic contraction leading to reduced energy demand and lower prices for our products and services and increased difficulty in collecting amounts owed to us by our customers. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have recently been affected by concerns over U.S. fiscal policy, including uncertainty regarding federal spending and tax policy, as well as the U.S. federal government’s debt ceiling and the federal deficit. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manners described above. 

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

A downgrade of our credit ratings might increase our cost of borrowing and could require us to provide collateral to our counterparties, negatively impacting our available liquidity. In addition, our ability to access capital markets could be limited by a downgrade of our credit ratings as well as by economic, market or other disruptions. Credit rating agencies perform independent analysis when assigning credit ratings. This analysis includes a number of criteria such as, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the ratings agencies.
We are exposed to the credit risk of our customers and counterparties, and our credit risk management may not be adequate to protect against such risk.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy or are required to make prepayments or provide security to satisfy credit concerns. However, our credit procedures and policies may not be adequate to fully eliminate customer and counterparty credit risk. Our customers and counterparties include industrial customers, local distribution companies, natural gas producers and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur, and, if significant, could have a material adverse effect on our business, results of operations, cash flows and financial condition.
Restrictions in our debt agreements and the amount of our indebtedness may affect our future financial and operating flexibility.
Our total outstanding long-term debt (including current portion) as of December 31, 2013, was $11,354 million.
The agreements governing our indebtedness contain covenants that restrict our and our material subsidiaries’ ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to make certain distributions during the continuation of an event of default, the ability of our subsidiaries to incur additional debt, and our and our material subsidiaries’ ability to enter into certain affiliate transactions and certain restrictive agreements. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply.
Our debt service obligations and the covenants described above could have important consequences. For example, they could:
•
Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;
•
Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes;
•
Diminish our ability to withstand a continued or future downturn in our business or the economy generally;
•
Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, the payments of dividends, general corporate purposes or other purposes;

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•
Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate, including limiting our ability to expand or pursue our business activities and preventing us from engaging in certain transactions that might otherwise be considered beneficial to us.
Our ability to comply with our debt covenants, to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to comply with these covenants, meet our debt service obligations or obtain future credit on favorable terms, or at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.
Our failure to comply with the covenants in the documents governing our indebtedness could result in events of default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Management’s Discussion and Analysis of Financial Condition and Liquidity”.
Institutional knowledge residing with current employees nearing retirement eligibility or with our former employees might not be adequately preserved.
We expect that a significant percentage of employees will become eligible for retirement over the next three years. In certain areas of our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age or their services are no longer available to us, we may not be able to replace them with employees of comparable knowledge and experience. In addition, we may not be able to retain or recruit other qualified individuals, and our efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.
Our hedging activities might not be effective and could increase the volatility of our results.
In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered, and may in the future enter into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used and may in the future use fixed-price, forward, physical purchase and sales contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.
The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.
In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted. The Dodd-Frank Act provides for statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be transacted on exchanges for which cash collateral will be required. These new rules and regulations could increase the cost of derivative contracts or reduce the availability of derivatives. Although we believe the derivative contracts that we enter into should not be impacted by position limits and should to a large extent be exempt from the requirement to trade these transactions on exchanges and to clear these transactions through a central clearing house or to post collateral, the impact upon our businesses will depend on the

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outcome of the implementing regulations that are continuing to be adopted by the Commodities Futures Trading Commission.
A number of our financial derivative transactions used for hedging purposes are currently executed on exchanges and cleared through clearing houses that already require the posting of margins based on initial and variation requirements. Final rules promulgated under the Dodd-Frank Act may require us to post additional cash or new margin to the clearing house or to our counterparties in connection with our hedging transactions. Posting such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures or other corporate purposes. A requirement to post cash collateral could therefore reduce our ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
Our costs and funding obligations for our defined benefit pension plans and costs for our other postretirement benefit plans are affected by factors beyond our control.
We have defined benefit pension plans covering substantially all of our U.S. employees and other post-retirement benefit plans covering certain eligible participants. The timing and amount of our funding requirements under the defined benefit pension plans depend upon a number of factors that we control, including changes to pension plan benefits, as well as factors outside of our control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase our funding requirements could have a significant adverse effect on our financial condition and results of operations.
One of our subsidiaries acts as the general partner of a publicly traded limited partnership, Williams Partners L.P. As such, this subsidiary’s operations may involve a greater risk of liability than ordinary business operations.
One of our subsidiaries acts as the general partner of WPZ, a publicly traded limited partnership. This subsidiary may be deemed to have undertaken fiduciary obligations with respect to WPZ as the general partner and to the limited partners of WPZ. Activities determined to involve fiduciary obligations to other persons or entities typically involve a higher standard of conduct than ordinary business operations and therefore may involve a greater risk of liability, particularly when a conflict of interest is found to exist. Our control of the general partner of WPZ may increase the possibility of claims of breach of fiduciary duties, including claims brought due to conflicts of interest (including conflicts of interest that may arise between WPZ, on the one hand, and its general partner and that general partner’s affiliates, including us, on the other hand). Any liability resulting from such claims could be material.
Our investments and projects located outside of the United States expose us to risks related to the laws of other countries, and the taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. These risks might delay or reduce our realization of value from our international projects.
We currently own and might acquire and/or dispose of material energy-related investments and projects outside the United States. The economic, political and legal conditions and regulatory environment in the countries in which we have interests or in which we might pursue acquisition or investment opportunities present risks that are different from or greater than those in the United States. These risks include, among others, delays in construction and interruption of business, as well as risks of renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, including with respect to the prices we realize for the commodities we produce and sell. The uncertainty of the legal environment in certain foreign countries in which we develop or acquire projects or make investments could make it more difficult to obtain nonrecourse project financing or other financing on suitable terms, could adversely affect the ability of certain customers to honor their obligations with respect to such projects or investments and could impair our ability to enforce our rights under agreements relating to such projects or investments.
Operations and investments in foreign countries also can present currency exchange rate and convertibility, inflation and repatriation risk. In certain situations under which we develop or acquire projects or make investments, economic and monetary conditions and other factors could affect our ability to convert to U.S. dollars our earnings denominated in foreign currencies. In addition, risk from fluctuations in currency exchange rates can arise when our foreign subsidiaries expend or borrow funds in one type of currency, but receive revenue in another. In such cases, an adverse change in exchange rates can reduce our ability to meet expenses, including debt service obligations. We may or may

32



not put contracts in place designed to mitigate our foreign currency exchange risks. We have some exposures that are not hedged and which could result in losses or volatility in our results of operations.
Failure of our service providers or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.
Certain of our accounting and information technology services are currently provided by third party vendors, and sometimes from service centers outside of the United States. Service provided pursuant to these agreements could be disrupted. Similarly, the expiration of such agreements or the transition of services between providers could lead to loss of institutional knowledge or service disruptions.
If there is a determination that the spin-off of WPX Energy, Inc (WPX) stock to our stockholders is taxable for U.S. federal income tax purposes because the facts, representations or undertakings underlying an IRS private letter ruling or a tax opinion are incorrect or for any other reason, then we and our stockholders could incur significant income tax liabilities.
In connection with our original separation plan that called for an initial public offering (IPO) of stock of WPX and a subsequent spin-off of our remaining shares of WPX to our stockholders, we obtained a private letter ruling from the IRS and an opinion of our outside tax advisor, to the effect that the distribution by us of WPX shares to our stockholders, and any related restructuring transaction undertaken by us, would not result in recognition for U.S. federal income tax purposes, of income, gain or loss to us or our stockholders under section 355 and section 368(a)(1)(D) of the Code, except for cash payments made to our stockholders in lieu of fractional shares of WPX common stock. In addition, we received an opinion from our outside tax advisor to the effect that the spin-off pursuant to our revised separation plan which was ultimately consummated on December 31, 2011, which did not involve an IPO of WPX shares, would not result in the recognition, for federal income tax purposes, of income, gain or loss to us or our stockholders under section 355 and section 368(a)(1)(D) of the Code, except for cash payments made to our stockholders in lieu of fractional shares of WPX. The private letter ruling and opinion have relied on or will rely on certain facts, representations, and undertakings from us and WPX regarding the past and future conduct of the companies’ respective businesses and other matters. If any of these facts, representations, or undertakings are, or become, incorrect or are not otherwise satisfied, including as a result of certain significant changes in the stock ownership of us or WPX after the spin-off, or if the IRS disagrees with any such facts and representations upon audit, we and our stockholders may not be able to rely on the private letter ruling or the opinion of our tax advisor and could be subject to significant income tax liabilities.
The spin-off may expose us to potential liabilities arising out of state and federal fraudulent conveyance laws and legal dividend requirements that we did not assume in our agreements with WPX.
The spin-off is subject to review under various state and federal fraudulent conveyance laws. A court could deem the spin-off or certain internal restructuring transactions undertaken by us in connection with the separation to be a fraudulent conveyance or transfer. Fraudulent conveyances or transfers are defined to include transfers made or obligations incurred with the actual intent to hinder, delay or defraud current or future creditors or transfers made or obligations incurred for less than reasonably equivalent value when the debtor was insolvent, or that rendered the debtor insolvent, inadequately capitalized or unable to pay its debts as they become due. A court could void the transactions or impose substantial liabilities upon us, which could adversely affect our financial condition and our results of operations. Whether a transaction is a fraudulent conveyance or transfer will vary depending upon the jurisdiction whose law is being applied. Under the separation and distribution agreement between us and WPX, from and after the spin-off, each of WPX and we are responsible for the debts, liabilities and other obligations related to the business or businesses which each owns and operates. Although we do not expect to be liable for any such obligations not expressly assumed by us pursuant to the separation and distribution agreement, it is possible that a court would disregard the allocation agreed to between the parties, and require that we assume responsibility for obligations allocated to WPX, particularly if WPX were to refuse or were unable to pay or perform the subject allocated obligations.
Item 1B. Unresolved Staff Comments
Not applicable.

33



Item 2. Properties
Please read “Business” for a description of the location and general character of our principal physical properties. We generally own our facilities, although a substantial portion of our pipeline and gathering facilities is constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across properties owned by others.
Item 3. Legal Proceedings
Environmental
Certain reportable legal proceedings involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings which are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.
In September 2007, the EPA requested, and Transco later provided, information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of Transco’s compliance with the Clean Air Act. On March 28, 2008, the EPA issued notices of violation alleging violations of Clean Air Act requirements at these compressor stations. Transco met with the EPA in May 2008 and submitted a response denying the allegations in June 2008. In May 2011, Transco provided additional information to the EPA pertaining to these compressor stations in response to a request they had made in February 2011. In August 2010, the EPA requested, and Transco provided, similar information for a compressor station in Maryland. Since 2011 we have not received any additional requests for information related to these facilities.
On February 12, 2013, the NMED issued a Notice of Violation to Four Corners related to the alleged modification of turbine units and a separator tank and alleged failure to conduct performance tests on certain facilities at the La Jara Compressor Station. Four Corners has been in discussions with the NMED since 2012 regarding the separator tank and other permitting issues. On January 9, 2014, the NMED withdrew the Notice of Violation and advised that no further action is required.
Other
The additional information called for by this item is provided in Note 17 – Contingent Liabilities and Commitments of the Notes to Consolidated Financial Statements included under Part II, Item 8. Financial Statements of this report, which information is incorporated by reference into this item.
Item 4. Mine Safety Disclosures
Not applicable.

34



Executive Officers of the Registrant
The name, age, period of service, and title of each of our executive officers as of February 21, 2014, are listed below.
Alan S. Armstrong
Director, Chief Executive Officer, and President
 
Age: 51
 
Position held since January 2011.
 
From 2002 to 2011, Mr. Armstrong served as Senior Vice President - Midstream and acted as President of our midstream business. From 1999 to 2002, Mr. Armstrong was Vice President, Gathering and Processing in our midstream business and from 1998 to 1999 was Vice President, Commercial Development. Since 2012, Mr.  Armstrong has served as a director of Access GP, the general partner of ACMP, a midstream natural gas service provider. Mr. Armstrong has served as a director of BOK Financial Corporation, a financial services company, since April 2013. Since 2011, Mr. Armstrong has also served as Chairman of the Board and Chief Executive Officer of the general partner of WPZ, where he served as Senior Vice President - Midstream from 2010, and Chief Operating Officer and a director from 2005.
Francis (Frank) E. Billings
Senior Vice President — Corporate Strategic Development
 
Age: 51
 
Position held since January 2014.
 
Mr. Billings served as a Senior Vice President - Northeast G&P from January 2013 to January 2014. Mr. Billings served as Vice President of our midstream gathering and processing business from 2011 until 2013 and as Vice President, Business Development from 2010 to 2011. Mr. Billings served as President of Cumberland Plateau Pipeline Company, a privately held company developing an ethane pipeline to serve the Marcellus shale area, from 2009 until 2010. From 2008 to 2009, Mr. Billings served as Senior Vice President of Commercial for Crosstex Energy, Inc. and Crosstex Energy L.P., an independent midstream energy services master limited partnership and its parent corporation. In 1988, Mr. Billings joined MAPCO Inc., which merged with a Williams subsidiary in 1998, serving in various management roles, including in 2008 as a Vice President in the midstream business. Mr. Billings is also the Senior Vice President - Corporate Strategic Development of the general partner of WPZ.
Allison G. Bridges
Senior Vice President — West
 
Age: 54
 
Position held since January 2013.
 
Ms. Bridges served as the Vice President and General Manager of Williams Gas Pipeline - West from 2010 until 2013. From 2003 to 2010, Ms. Bridges was Vice President Commercial Operations for Northwest Pipeline. Ms. Bridges joined Transco in 1981, now a subsidiary of us and WPZ, holding various management positions in accounting, rates, planning and business development. Ms. Bridges is also the Senior Vice President - West of the general partner of WPZ. Ms. Bridges has served as a member of the Management Committee of Northwest Pipeline since 2007.

35



Donald R. Chappel
Senior Vice President and Chief Financial Officer
 
Age: 62
 
Position held since April 2003.
 
Prior to joining us, Mr. Chappel held various financial, administrative and operational leadership positions. Since 2012, Mr. Chappel has served as a director of Access GP, the general partner of ACMP, in which we own an interest. Mr. Chappel has also served as a member of the Management Committee of Northwest Pipeline since 2007. Mr. Chappel was Chief Financial Officer from 2007 and a director from 2008 of Williams Pipeline GP LLC, the general partner of Williams Pipeline Partners L.P., until its merger with WPZ in 2010. Mr. Chappel is a director of SUPERVALU, Inc. (a grocery and pharmacy company). Mr. Chappel also serves as Chief Financial Officer and a director of the general partner of WPZ.
John R. Dearborn
Senior Vice President - NGL & Petchem Services
 
Age: 56
 
Position held since April 2013.
 
Mr. Dearborn served as a senior leader for Saudi Basic Industries Corporation, a petrochemical company, from 2011 to 2013. From 2001 to 2011, Mr. Dearborn served in a variety of leadership positions with the Dow Chemical Company (DOW). Mr. Dearborn also worked for Union Carbide Corporation, prior to its merger with DOW, from 1981 to 2001 where he served in several leadership roles. Mr. Dearborn also serves as Senior Vice President - NGL & Petchem Services of the general partner of WPZ.
Robyn L. Ewing
Senior Vice President and Chief Administrative Officer
 
Age: 58
 
Position held since April 2008.
 
From 2004 to 2008, Ms. Ewing was Vice President of Human Resources. Prior to joining Williams, Ms. Ewing worked at MAPCO, which merged with Williams in 1998. Ms. Ewing began her career with Cities Service Company in 1976.

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

36



Fred E. Pace
Senior Vice President — E&C (Engineering and Construction)
 
Age: 52
 
Position held since January 2013.
 
From 2011 until 2013, Mr. Pace served Williams in project engineering and development roles, including service as Vice President Engineering and Construction for our midstream business. From 2009 to 2011, Mr. Pace was the managing member of PACE Consulting, LLC, an engineering and consulting firm serving the energy industry. In 2003, Mr. Pace co-founded Clear Creek Natural Gas, LLC, later known as Clear Creek Energy Services, LLC, a provider of engineering, construction, and operational services to the energy industry where he served as Chief Executive Officer until 2009. Mr. Pace has over 30 years of experience in the engineering, construction, operation, and project management areas of the energy industry, including prior service with Williams from 1985 to 1990. Mr. Pace also serves as Senior Vice President - E&C of the general partner of WPZ.
Brian L. Perilloux
Senior Vice President — Operational Excellence
 
Age: 52
 
Position held since January 2013.
 
Mr. Perilloux served as a Vice President of our midstream business from 2011 until 2013. From 2007 to 2011, Mr. Perilloux served in various roles in our midstream business, including engineering and construction roles. Prior to joining Williams, Mr. Perilloux was an officer of a private international engineering and construction company. Mr. Perilloux also serves as Senior Vice President - Operational Excellence of the general partner of WPZ.
Craig L. Rainey
Senior Vice President and General Counsel
 
Age: 61
 
Position held since January 2012.
 
Mr. Rainey has served as Senior Vice President and General Counsel since January 2012. From 2001 to 2012, Mr. Rainey served as an Assistant General Counsel of Williams, primarily supporting our midstream business and former exploration and production business. Mr. Rainey joined Williams in 1999 as a senior counsel and has practiced law since 1977. Mr. Rainey is also the General Counsel of the general partner of WPZ.
James E. Scheel
Senior Vice President — Senior Vice President - Northeast G&P
 
Age: 49
 
Position held since January 2014.
 
From 2012 to 2014 Mr. Scheel served as Senior Vice President - Corporate Strategic Development. From 2011 until 2012, Mr. Scheel served as Vice President of Business Development for our midstream business. Mr. Scheel joined Williams in 1988 and has served in leadership roles in business strategic development, engineering and operations, our NGL business, and international operations. Since 2012, Mr. Scheel has served as a director of Access GP, the general partner of ACMP, in which we own an interest. Mr. Scheel also serves as a director and as Senior Vice President - Northeast G&P of the general partner of WPZ.

37



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



38



PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the New York Stock Exchange under the symbol “WMB.” At the close of business on February 21, 2014, we had approximately 8,405 holders of record of our common stock. The high and low sales price ranges (New York Stock Exchange composite transactions) and dividends declared by quarter for each of the past two years are as follows:
 
High
 
Low
 
Dividend
2013
 
 
 
 
 
First Quarter
$
38.00

 
$
33.09

 
$
0.33875

Second Quarter
38.57

 
31.25

 
0.3525

Third Quarter
36.94

 
32.36

 
0.36625

Fourth Quarter
38.68

 
33.98

 
0.38

2012
 
 
 
 
 
First Quarter
$
32.09

 
$
26.21

 
$
0.25875

Second Quarter
34.63

 
27.25

 
0.30

Third Quarter
35.39

 
28.47

 
0.3125

Fourth Quarter
37.56

 
30.55

 
0.325

Some of our subsidiaries’ borrowing arrangements may limit the transfer of funds to us. These terms have not impeded, nor are they expected to impede, our ability to pay dividends.
Performance Graph
Set forth below is a line graph comparing our cumulative total stockholder return on our common stock (assuming reinvestment of dividends) with the cumulative total return of the S&P 500 Stock Index and the Bloomberg U.S. Pipeline Index for the period of five fiscal years commencing January 1, 2009. The Bloomberg U.S. Pipeline Index is composed of Enbridge, Kinder Morgan, Inc., Kinder Morgan Management, LLC, ONEOK, Inc., Spectra Energy, TransCanada Corp., and Williams. The graph below assumes an investment of $100 at the beginning of the period.


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

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Item 6. Selected Financial Data
The following financial data at December 31, 2013 and 2012, and for each of the three years in the period ended December 31, 2013, should be read in conjunction with the other financial information included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting records.
 
2013
 
2012
 
2011
 
2010
 
2009
 
(Millions, except per-share amounts)
Revenues
$
6,860

 
$
7,486

 
$
7,930

 
$
6,638

 
$
5,278

Income (loss) from continuing operations (1)
679

 
929

 
1,078

 
271

 
346

Amounts attributable to The Williams Companies, Inc.:
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations (1)
441

 
723

 
803

 
104

 
206

Diluted earnings (loss) per common share:
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations (1)
0.64

 
1.15

 
1.34

 
0.17

 
0.35

Total assets at December 31 (2) (3)
27,142

 
24,327

 
16,502

 
24,972

 
25,280

Commercial paper and long-term debt due within one year at December 31 (4)
226

 
1

 
353

 
508

 
17

Long-term debt at December 31 (3)
11,353

 
10,735

 
8,369

 
8,600

 
8,259

Stockholders’ equity at December 31 (2) (3)
4,864

 
4,752

 
1,296

 
6,803

 
7,990

Cash dividends declared per common share
1.438

 
1.196

 
0.775

 
0.485

 
0.44

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

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

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

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


40



Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas, NGLs, and olefins. Our operations are located principally in the United States, but span from the deepwater Gulf of Mexico to the Canadian oil sands, and are organized into the Williams Partners, Williams NGL & Petchem Services, and Access Midstream Partners reportable segments. All remaining business activities are included in Other.
Williams Partners
Williams Partners includes WPZ, our consolidated master limited partnership, which includes two interstate natural gas pipelines, as well as investments in natural gas pipeline-related companies, which serve regions from the San Juan basin in northwestern New Mexico and southwestern Colorado to Oregon and Washington and from the Gulf of Mexico to the northeastern United States. WPZ also includes natural gas gathering, processing, and treating facilities and oil gathering and transportation facilities located primarily in the Rocky Mountain, Gulf Coast, and Marcellus Shale regions of the United States. WPZ also owns a 5/6 interest in an olefin production facility, along with a refinery grade propylene splitter and pipelines in the Gulf region. As of December 31, 2013, we own approximately 64 percent of the interests in WPZ, including the interests of the general partner, which is wholly owned by us, and incentive distribution rights.
Williams Partners’ ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission and midstream infrastructures where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers and utilizing our low cost-of-capital to invest in growing markets, including the deepwater Gulf of Mexico, the Marcellus Shale, the Gulf Coast Region, and areas of increasing natural gas demand.
Williams Partners’ interstate transmission and related storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have little near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
Williams NGL & Petchem Services
Williams NGL & Petchem Services includes our oil sands offgas processing plant near Fort McMurray, Alberta and our NGL/olefin fractionation facility and B/B splitter facility at Redwater, Alberta. We produce NGLs and propylene. Our NGL products include propane, normal butane, isobutane/butylene (butylene), and condensate. Williams NGL & Petchem Services also includes certain other domestic olefins pipeline assets including Bluegrass Pipeline, a new joint project, which would connect processing facilities in the Marcellus and Utica shale-gas areas in the U.S. Northeast to growing petrochemical and export markets in the U.S. Gulf Coast.
Access Midstream Partners
Access Midstream Partners includes our equity method investment in ACMP, acquired in December 2012. As of December 31, 2013, this investment includes a 23 percent limited partner interest in ACMP and a 50 percent indirect interest in Access GP, including incentive distribution rights. ACMP is a publicly traded master limited partnership that owns, operates, develops, and acquires natural gas gathering systems and other midstream energy assets, which bolsters our position in the Marcellus and Utica shale plays and adds diversity via the Eagle Ford, Haynesville, Barnett, Mid-Continent, and Niobrara areas.
Unless indicated otherwise, the following discussion and analysis of critical accounting estimates, results of operations, and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this document.

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-in-kind Class D units, all of which will be convertible to common units at a future date. The agreement also provides that WPZ can issue additional Class D units to us on a quarterly basis through 2015 for up to a total of $200 million in cash for the purpose of funding certain facility expansions.
    
Dividend Growth
We increased our quarterly dividends from $0.325 per share in the fourth quarter of 2012 to $0.380 per share in the fourth quarter of 2013. Also, consistent with our expectation of receiving increasing cash distributions from our interests in WPZ and Access Midstream Partners, we expect to increase our dividend on a quarterly basis. Our Board of Directors has approved a dividend of $0.4025 per share for the first quarter of 2014 and we expect approximately 20 percent annual increase in total dividends in both 2014 and 2015.
Overview
Income (loss) from continuing operations attributable to The Williams Companies, Inc., for the year ended December 31, 2013, changed unfavorably by $282 million compared to the year ended December 31, 2012. This change primarily reflects a $206 million decline in Williams Partners segment profit primarily due to lower NGL margins driven by reduced ethane recoveries and lower olefins margins as a result of the Geismar Incident, partially offset by higher fee-based revenues; $61 million in segment profit from our investment in ACMP acquired at the end of 2012; and $99 million of deferred income tax expense recognized in 2013 related to undistributed earnings of certain foreign operations that are no longer considered permanently reinvested. See additional discussion in Results of Operations.
Abundant and low-cost natural gas reserves in the United States continue to drive strong demand for midstream and pipeline infrastructure. We believe that we have successfully positioned our energy infrastructure businesses for significant future growth.
Williams Partners
Geismar Incident
On June 13, 2013, an explosion and fire occurred at WPZ’s Geismar olefins plant. The fire was extinguished on the day of the incident. The incident (Geismar Incident) rendered the facility temporarily inoperable and resulted in significant human, financial, and operational effects.
We have substantial insurance coverage for repair and replacement costs, lost production and additional expenses related to the incident as follows:
•
Property damage and business interruption coverage with a combined per-occurrence limit of $500 million and retentions (deductibles) of $10 million per occurrence for property damage and a 60-day waiting period per occurrence for business interruption;
•
General liability coverage with per-occurrence and aggregate annual limits of $610 million and retentions (deductibles) of $2 million per occurrence;
•
Workers’ compensation coverage with statutory limits and retentions (deductibles) of $1 million total per occurrence.

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) expense – net within Costs and expenses in our Consolidated Statement of Income.
Following the repair and plant expansion, the Geismar plant is expected to be in operation in June 2014. We expect our insurance coverage will significantly mitigate our financial loss. We currently estimate approximately $430 million of total cash recoveries from insurers related to business interruption and approximately $70 million related to the repair of the plant. Of these amounts, we received $50 million of insurance proceeds during 2013. In February 2014, the insurer agreed to pay a second installment of $125 million, which is expected to be received in the first quarter of 2014. We are impacted by certain uninsured losses, including amounts associated with the 60-day waiting period for business interruption, as well as other deductibles, policy limits, and uninsured expenses. Our assumptions and estimates, including the timing for the expanded plant return to operation, repair cost estimates, and insurance proceeds associated with our property damage and business interruption coverage are subject to various risks and uncertainties that could cause the actual results to be materially different.
Mid-Atlantic Connector
The Mid-Atlantic Connector Project involved an expansion of Transco’s mainline from an existing interconnection with East Tennessee Natural Gas in North Carolina to markets as far downstream as Maryland. We placed the project into service in the first quarter of 2013, and it increased capacity by 142 Mdth/d.
Overland Pass Pipeline
Through our equity investment in OPPL, we completed the construction of a pipeline expansion in the second quarter of 2013, which increased the pipeline’s capacity to 255 Mbbls/d. In addition, a new connection was completed in April 2013 to bring new NGL volumes to OPPL from the Bakken Shale in the Williston basin.

Three Rivers Midstream

In April 2013, we announced an agreement to launch a new midstream joint project to provide gas gathering and gas processing services for production located in northwest Pennsylvania. The project is expected to invest in both wet-gas handling infrastructure and dry-gas infrastructure serving the Marcellus and Utica Shale wells in the area. We will initially own substantially all of the new project, Three Rivers Midstream, and operate the assets. Our partner has the right to invest capital and increase its ownership to a maximum of 50 percent by July 2015. Further development has been delayed pending additional evaluation of producers’ drilling plans.
Gulfstar One
Effective April 1, 2013, WPZ sold a 49 percent interest in Gulfstar One LLC (Gulfstar One) to a third party for $187 million, representing their proportionate share of estimated capital expenditures to date for the construction of Gulfstar FPS™, which is a proprietary floating production system and has been under construction since late 2011. It is supported by multiple agreements with two major producers to provide production handling, export pipeline, oil and gas gathering and gas processing services for the Tubular Bells field development located in the eastern deepwater Gulf of Mexico. The Gulfstar FPS™ will tie into our wholly owned oil and gas gathering and gas processing systems in the eastern Gulf of Mexico. Gulfstar FPS™ is expected to have an initial capacity of 60 Mbbls/d, up to 200 MMcf/d of natural gas and the capability to provide seawater injection services. We expect Gulfstar FPS™ to be capable of serving as a central host facility for other deepwater prospects in the area. The project is expected to be in service in the third quarter 2014. In December 2013, Gulfstar One agreed to host the Gunflint development, which will result in an expansion

43



of the Gulfstar One system to provide production handling capacity of 20 Mbbls/d and 40 MMcf/d for Gunflint. The project has a first oil target of mid-2016, dependent on the producer’s development activities.
Marcellus Shale
In the second quarter of 2013, we completed an expansion to our natural gas gathering system, processing facilities, and fractionator in our Ohio Valley Midstream business of the Marcellus Shale including a third turbo-expander at our Fort Beeler facility, which added 200 MMcf/d of processing capacity. In the first half of 2014, we expect to add fractionation capacity at our Moundsville fractionators bringing the NGL handling capacity to approximately 43 Mbbls/d, complete our first turbo-expander at our Oak Grove facility to add 200 MMcf/d of processing capacity, and finalize the construction of our first deethanizer with a capacity of 40 Mbbls/d and the associated 50-mile ethane line to Houston, Pennsylvania.
Mid-South
The Mid-South expansion project involved an expansion of Transco’s mainline from Station 85 in Choctaw County, Alabama to markets as far downstream as North Carolina. We placed the first phase of the project into service in the third quarter of 2012, which increased capacity by 95 Mdth/d. The second phase was placed into service in the second quarter of 2013, which increased capacity by an additional 130 Mdth/d.
Northeast Supply Link
The Northeast Supply Link Project involved an expansion of Transco’s existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. The project was placed into service in the fourth quarter of 2013 and increased capacity by 250 Mdth/d.
Filing of rate cases
On August 31, 2012, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceeding. The new rates became effective March 1, 2013, subject to refund and the outcome of the hearing. On August 27, 2013, Transco filed a stipulation and agreement with the FERC proposing to resolve all issues in this proceeding without the need for a hearing (Agreement). On December 6, 2013, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement will become effective March 1, 2014. We have provided a reserve for rate refunds of $98 million which we believe is adequate for required refunds as of December 31, 2013, under the Agreement. Refunds will be made on or before April 30, 2014.
Caiman II
As a result of planned contributions through the second quarter of 2014, we expect, subject to regulatory approval, to increase our ownership in Caiman II from 47.5 percent up to approximately 59 percent. These additional contributions are used to fund a portion of Blue Racer Midstream, a joint project which comprises an expansion to gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica Shale.
Atlantic Sunrise
The Atlantic Sunrise Expansion Project involves an expansion of our existing natural gas transmission system along with greenfield facilities to provide firm transportation from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in Alabama.  We plan to file an application with the FERC in the second quarter of 2015 for approval of the project.  We plan to place the project into service during the second half of 2017 assuming timely receipt of all necessary regulatory approvals and it is expected to increase capacity by 1,700 Mdth/d.

44



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.

45



Williams NGL & Petchem Services
Canadian PDH Facility
During the first quarter of 2013, we announced plans to build Canada’s first propane dehydrogenation (PDH) facility located in Alberta. The new PDH facility is expected to produce approximately 1.1 billion pounds annually, significantly increasing Williams’ production of polymer-grade propylene currently at 180 million pounds annually. The project is in the development stage and is expected to start-up in the second quarter of 2017. This project is not part of the Canadian operations that are expected to be acquired by WPZ.
Bluegrass Pipeline and Moss Lake
In the second quarter of 2013, we formed a joint project to develop the Bluegrass Pipeline. We own a 50 percent percent interest in Bluegrass Pipeline (a consolidated entity), which would connect processing facilities in the Marcellus and Utica shale-gas areas in the U.S. Northeast to growing petrochemical and export markets in the U.S. Gulf Coast. The proposed pipeline would deliver mixed NGLs from these producing areas to proposed new fractionation and storage facilities, which would have connectivity to petrochemical facilities and product pipelines along the coasts of Louisiana and Texas. We are in discussions with potential customers regarding the commitments to the pipeline. Completion of this project is subject to all necessary or required approvals, elections, and actions, as well as execution of formal customer commitments. We currently estimate that the Bluegrass Pipeline will be placed in-service in mid-to-late 2016.
Through our 50 percent equity investment in Moss Lake Fractionation LLC, the project would also include constructing a new large-scale fractionation plant and expanding NGL storage facilities in Louisiana. In October 2013, we announced a related joint project, Moss Lake LPG Terminal, which explores the development of a new liquefied petroleum gas export terminal and related facilities on the Gulf Coast to provide customers access to international markets.
Ethane Recovery Project
In December 2013, we completed the ethane recovery project, which is an expansion of our Canadian facilities which allows us to recover ethane/ethylene mix from our operations that process offgas from the Alberta oil sands. We modified our oil sands offgas extraction plant near Fort McMurray, Alberta, and constructed a deethanizer at our Redwater fractionation facility that processes approximately 10 Mbbls/d of ethane/ethylene mix. We have signed a long-term contract to provide the ethane/ethylene mix to a third-party customer. This project is included in the Canadian operations that are expected to be acquired by WPZ.
Company Outlook

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

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

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

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

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:
•
General economic, financial markets, or industry downturn;
•
Unexpected significant increases in capital expenditures or delays in capital project execution;
•
Lower than anticipated or delay in receiving insurance recoveries associated with the Geismar Incident;
•
Limited availability of capital due to a change in our financial condition, interest rates, market or industry conditions;
•
Lower than expected distributions, including IDRs, from WPZ. WPZ’s liquidity could also be impacted by a lack of adequate access to capital markets to fund its growth;
•
Counterparty credit and performance risk;
•
Decreased volumes from third parties served by our midstream business;
•
Lower than anticipated energy commodity prices and margins;
•
Changes in the political and regulatory environments;
•
Physical damages to facilities, including damage to offshore facilities by named windstorms;
•
Reduced availability of insurance coverage.
We continue to address these risks through disciplined investment strategies, sufficient liquidity from cash and cash equivalents and available capacity under our revolving credit facilities.

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

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

Williams Partners

Commodity price changes

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

In 2014, we anticipate higher overall commodity prices compared to 2013:
•
Natural gas prices are expected to be higher in part due to the additional demand to replace the gas volumes withdrawn during the colder than normal weather over the past winter season.

47



•
Ethane prices are expected to be somewhat higher due to a modest increase in demand as well as slightly higher natural gas prices.  
•
Propane prices are expected to be higher from an increase in exports and higher natural gas prices.
•
Propylene prices are expected to be comparable to 2013 prices.
•
Ethylene prices are expected to be slightly lower as compared to 2013 prices. The overall ethylene crack spread is also expected to be slightly lower due to the anticipated lower sales price and a projected higher ethane price. 

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

•
In Williams Partners’ northeast region, we anticipate significant growth compared to the prior year in our natural gas gathering and processing volumes as our infrastructure grows to support drilling activities in the region.
•
In Williams Partners’ Transco and Northwest Pipeline businesses, we anticipate higher natural gas transportation volumes compared to 2013, as a result of expansion projects placed into service in 2013 and anticipated to be placed in service in 2014.
•
In Williams Partners’ Gulf Coast region, we expect higher production handling volumes compared to 2013, following the scheduled completion of Gulfstar FPS™ in third quarter 2014.
•
In Williams Partners’ western region, we anticipate an unfavorable impact in equity NGL volumes in 2014 compared to 2013, primarily due to a customer contract that expired in September 2013.
•
In 2014, Williams Partners’ anticipates a continuation of periods when it will not be economical to recover ethane.

Olefin production volumes

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

Other
•
Williams Partners’ Gulf olefins business expects to receive insurance recoveries under its business interruption policy related to the Geismar Incident that will favorably impact our operating results in 2014.
•
Williams Partners’ expects higher operating expenses in 2014 compared to 2013, including depreciation expense related to its growing operations in its northeast region and expansion projects in its gas pipeline and Gulf olefins businesses.
•
Williams Partners’ expects higher equity earnings compared to 2013 following the scheduled completion of Discovery’s Keathley Canyon Connector™ lateral in the fourth quarter of 2014.


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Eminence Storage Field leak

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

In September 2011, we filed an application with the FERC seeking authorization to abandon these four caverns. In February 2013, the FERC issued an order approving the abandonment. We estimate the remaining cost to complete the abandonment of the caverns will be approximately $7 million, and is expected to be spent through the first half of 2014.

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

Williams NGL & Petchem Services

Commodity margin and volume changes

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

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

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

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

Access Midstream Partners

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

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


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Expansion Projects

We expect to invest total capital in 2014 among our business segments as follows:
 
Low
 
High
 
(Millions)
Segment:
 
 
 
Williams Partners
$
3,025

 
$
3,525

Williams NGL & Petchem Services
775

 
1,075


Our ongoing major expansion projects include the following:

Williams Partners

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

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

Mobile Bay South III
In July 2013, we filed an application with the FERC for an expansion of Transco’s Mobile Bay line south from Station 85 in west central Alabama to delivery points along the line. We plan to place the project into service during the second quarter of 2015 and it is expected to increase capacity on the line by 225 Mdth/d.

Constitution Pipeline
In June 2013, we filed an application with the FERC for authorization to construct and operate the new jointly owned Constitution pipeline. We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will be the operator of Constitution. The 120-mile Constitution pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We plan to place the project into service in late 2015 to 2016, with an expected capacity of 650 Mdth/d. The pipeline is fully subscribed with two shippers.

Northeast Connector
In April 2013, we filed an application with the FERC to expand Transco’s existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. We plan to place the project into service during the second half of 2014, and expect it to increase capacity by 100 Mdth/d.


50



Rockaway Delivery Lateral
In January 2013, we filed an application with the FERC for Transco to construct a three-mile offshore lateral to a distribution system in New York. We plan to place the project into service during the second half of 2014, the capacity of the lateral is expected to be 647 Mdth/d.

Virginia Southside
In December 2012, we filed an application with the FERC to expand Transco’s existing natural gas transmission system from New Jersey to a proposed power station in Virginia and a delivery point in North Carolina. We plan to place the project into service during the third quarter of 2015, and expect it to increase capacity by 270 Mdth/d.

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

•
As previously discussed, we completed construction at our Fort Beeler facility in the Marcellus Shale, which added 200 MMcf/d of processing capacity in the second quarter of 2013. We have several significant projects under construction with targeted construction completion in the first half of 2014. We are completing a 43 Mbbls/d expansion of the Moundsville fractionator, installation of 40 Mbbls/d of deethanization capacity, a 50-mile ethane pipeline, condensate stabilization, and the first 200 MMcf/d of processing at Oak Grove.

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

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

Gulfstar One
We will design, construct, and install our Gulfstar FPS™, a spar-based floating production system that utilizes a standard design approach with a capacity of 60 Mbbls/d of oil, up to 200 MMcf/d of natural gas, and the capability to provide seawater injection services, as previously discussed. Construction is under way and the project is expected to be in service in the third quarter 2014. The previously discussed expansion that increases Gulfstar One’s production handling capacity related to the Gunflint Development is expected to be completed in mid-2016, dependent on the producer’s development activities.

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


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Geismar
As a result of the Geismar Incident, the expansion of our Geismar olefins production facility is expected to be completed when the Geismar plant returns to operation, which is expected to occur in June 2014. The expansion is expected to increase the facility’s ethylene production capacity by 600 million pounds per year to a new annual capacity of 1.95 billion pounds. The additional capacity will be wholly owned by us and is expected to increase our ownership of the Geismar production facility from the current 83.3 percent.

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

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

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

Gulf Coast Expansion
In November 2012, we acquired 10 liquids pipelines in the Gulf Coast region. The acquired pipelines will be combined with an organic build-out of several projects to expand our petrochemical services in that region. The projects include the construction and commissioning of pipeline systems capable of transporting various products in the Gulf Coast region. The projects are expected to be placed into service beginning in late 2014 through 2015.

Bluegrass Pipeline
As previously discussed, in the second quarter we formed a joint project to develop the proposed Bluegrass Pipeline. Pre-construction activities are under way and we currently estimate that the project will be placed in-service in mid-to-late 2016.
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We have reviewed the selection, application, and disclosure of these

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.
 
Benefit Cost
 
Benefit Obligation
 
One-
Percentage-
Point
Increase
 
One-
Percentage-
Point
Decrease
 
One-
Percentage-
Point
Increase
 
One-
Percentage-
Point
Decrease
 
(Millions)
Pension benefits:
 
 
 
 
 
 
 
Discount rate
$
(6
)
 
$
7

 
$
(114
)
 
$
133

Expected long-term rate of return on plan assets
(11
)
 
11

 
—

 
—

Rate of compensation increase
2

 
(1
)
 
7

 
(6
)
Other postretirement benefits:
 
 
 
 
 
 
 
Discount rate
1

 
1

 
(20
)
 
24

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

 
—

 
—

Assumed health care cost trend rate
5

 
(4
)
 
7

 
(6
)
Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on the average rate of return expected on the funds invested in the plans. We determine our long-term expected rates of return on plan assets using our expectations of capital market results, which includes an analysis of historical results as well as forward-looking projections. These capital market expectations are based on a period of at least 10 years and take into account our investment strategy and mix of assets, which is weighted toward domestic and international equity securities. We develop our expectations using input from several external sources, including consultation with our third-party independent investment consultant. The forward-looking capital market projections are developed using a consensus of economists’ expectations for inflation, GDP growth, and dividend yield along with expected changes in risk premiums. The capital market return projections for specific asset classes in the investment portfolio are then applied to the relative weightings of the asset classes in the investment portfolio. The resulting rates are an estimate of future results and, thus, likely to be different than actual results.
In 2013, the benefit plans’ assets reflected strong equity performance as well as negative returns from the fixed income strategies. While the 2013 investment performance was greater than our expected rates of return, the expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance. Changes to our asset allocation would also impact these expected rates of return. Our expected long-term rate of return on plan assets used for our pension plans was 6.3 percent in 2012. In 2013, we reduced our expected long-term rate of return on pension assets to 5.9 percent. This reduction was implemented due to a downward trend in long-term capital market expectations. The 2013 actual return on plan assets for our pension plans was approximately 15.5 percent. The 10-year average rate of return on pension plan assets through December 2013 was approximately 5.7 percent.
The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans. The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due. Increases in the discount rates decrease the obligation and, generally, decrease the related cost. The discount rates for

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 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term, high-quality debt securities as well as by the duration of our plans’ liabilities. The weighted-average discount rate used to measure our pension plans’ benefit obligation increased during 2013 by 125 basis points, which significantly contributed to the actuarial gain of $173 million in the current year.
The expected rate of compensation increase represents average long-term salary increases. An increase in this rate causes the pension obligation and cost to increase.
The assumed health care cost trend rates are based on national trend rates adjusted for our actual historical cost rates and plan design. An increase in this rate causes the other postretirement benefit obligation and cost to increase.
Goodwill
At December 31, 2013, our Consolidated Balance Sheet includes $646 million of goodwill. We performed our annual assessment of goodwill for impairment as of October 1. All of our goodwill is allocated to WPZ’s Northeast gathering and processing business (the reporting unit). In our evaluation, our estimate of the fair value of the reporting unit exceeded its carrying value by 15 percent, including goodwill, and thus no impairment loss was recognized in 2013. The fair value of WPZ’s Northeast gathering and processing business was estimated by an income approach utilizing discounted cash flows and corroborated with a market capitalization analysis.
Judgments and assumptions are inherent in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of an impairment charge in the consolidated financial statements. Our calculation of fair value used a discount rate of 10.5 percent. We estimate that an increase of approximately 140 basis points in the discount rate could result in a fair value of the reporting unit below its carrying value, all other variables held constant.
Equity-method investments
At December 31, 2013, our Consolidated Balance Sheet includes approximately $4.4 billion of investments that are accounted for under the equity method of accounting. We evaluate these investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair value of our investments.
If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge. Events or changes in circumstances that may be indicative of an other-than-temporary decline in value will vary by investment, but may include:
•
A significant or sustained decline in the market value of a publicly-traded investee;
•
Lower than expected cash distributions from investees (including incentive distributions);
•
Significant asset impairments or operating losses recognized by investees;
•
Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees;
•
Significant delays in or failure to complete significant growth projects of investees.

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

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


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 December 31, 2013. The results of operations by segment are discussed in further detail following this consolidated overview discussion. 
 
Years Ended December 31,
 
2013
 
$ Change
from
2012*
 
% Change
from
2012*
 
2012
 
$ Change
from
2011*
 
% Change
from
2011*
 
2011
 
(Millions)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
Service revenues
$
2,939

 
+210

 
+8%

 
$
2,729

 
+197
 
+8%
 
$
2,532

Product sales
3,921

 
-836

 
-18%

 
4,757

 
-641
 
-12%
 
5,398

Total revenues
6,860

 
 
 
 
 
7,486

 
 
 
 
 
7,930

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
Product costs
3,027

 
+469

 
+13%

 
3,496

 
+438
 
+11%
 
3,934

Operating and maintenance expenses
1,097

 
-70

 
-7%

 
1,027

 
-37
 
-4%
 
990

Depreciation and amortization expenses
815

 
-59

 
-8%

 
756

 
-95
 
-14%
 
661

Selling, general, and administrative expenses
512

 
+59

 
+10%

 
571

 
-94
 
-20%
 
477

Other (income) expense — net
34

 
-10

 
-42%

 
24

 
-23
 
NM
 
1

Total costs and expenses
5,485

 
 
 
 
 
5,874

 
 
 
 
 
6,063

Operating income (loss)
1,375

 
 
 
 
 
1,612

 
 
 
 
 
1,867

Equity earnings (losses)
134

 
+23

 
+21%

 
111

 
-44
 
-28%
 
155

Interest expense
(510
)
 
-1

 
0%

 
(509
)
 
+64
 
+11%
 
(573
)
Other investing income — net
81

 
+4

 
+5%

 
77

 
+64
 
NM
 
13

Early debt retirement costs
—

 
—

 
—

 
—

 
+271
 
+100%
 
(271
)
Other income (expense) — net
—

 
+2

 
+100%

 
(2
)
 
-13
 
NM
 
11

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

 
 
 
 
 
1,289

 
 
 
 
 
1,202

Provision (benefit) for income taxes
401

 
-41

 
-11%

 
360

 
-236
 
-190%
 
124

Income (loss) from continuing operations
679

 
 
 
 
 
929

 
 
 
 
 
1,078

Income (loss) from discontinued operations
(11
)
 
-147

 
NM

 
136

 
+553
 
NM
 
(417
)
Net income (loss)
668

 
 
 
 
 
1,065

 
 
 
 
 
661

Less: Net income attributable to noncontrolling interests
238

 
-32

 
-16%

 
206

 
+79
 
+28%
 
285

Net income (loss) attributable to The Williams Companies, Inc.
$
430

 
 
 
 
 
$
859

 
 
 
 
 
$
376

_______
*
+ = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.
2013 vs. 2012
The increase in Service revenues is primarily due to higher fee revenues associated with the growth in the businesses acquired in the 2012 Caiman and Laser Acquisitions, as well as contributions from the processing and fractionation facilities placed in service in the latter half of 2012 and in 2013. Additionally, natural gas transportation fee revenues increased from expansion projects placed into service in 2012 and 2013 and new rates effective during first-quarter 2013. Partially offsetting these increases are decreased gathering and processing fee revenues driven by lower volumes in the Piceance, Four Corners, and eastern Gulf Coast areas.

56



The decrease in Product sales is primarily due to lower NGL production revenues driven by reduced ethane recoveries and decreases in average NGL per-unit sales prices, as well as lower olefin production revenues primarily from the loss of production as a result of the Geismar Incident, partially offset by higher olefin per-unit sales prices. Additionally, marketing revenues decreased resulting from lower NGL per-unit prices and lower crude oil and ethane volumes, partially offset by higher non-ethane volumes. The changes in marketing revenues are more than offset by similar changes in marketing purchases, reflected above as Product costs.
The decrease in Product costs is primarily due to lower NGL marketing purchases resulting from lower NGL prices and lower crude oil volumes, partially offset by higher non-ethane volumes. The changes in marketing purchases are substantially offset by similar changes in marketing revenues. In addition, olefin feedstock purchases decreased reflecting lower volumes and lower average per-unit feedstock costs. Costs associated with the production of NGLs also decreased primarily resulting from lower ethane recoveries, partially offset by an increase in average natural gas prices.
The increase in Operating and maintenance expenses is primarily associated with the subsequent growth in the operations of the businesses acquired in the Caiman and Laser Acquisitions, a scheduled third-quarter 2013 shutdown to conduct maintenance at our Canadian olefins facility, and $13 million of costs incurred under our insurance deductibles resulting from the Geismar Incident. These increases are partially offset by lower compressor and natural gas pipeline maintenance and repair expenses primarily due to the absence of expenses related to the substantial completion of our natural gas pipeline integrity management plan during 2012 and lower operating costs in our Four Corners area, which experienced lower volumes.
The increase in Depreciation and amortization expenses reflects a full year of depreciation and amortization expense in 2013 related to the Caiman and Laser Acquisitions and depreciation on subsequent infrastructure additions, increased depreciation of certain assets that were decommissioned in the third quarter of 2013 in preparation for the completion of the ethane recovery system, as well as higher depreciation on the Boreal Pipeline which was placed into service in 2012. The absence of increased depreciation in 2012 on certain assets in the Gulf Coast region resulting from a change in the estimated useful lives partially offset these increases.
The decrease in Selling, general, and administrative expenses (SG&A) is primarily due to the absence of reorganization related costs in 2012 and the absence of acquisition and transition costs incurred in 2012. (See Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements.)
Other (income) expense – net within Operating income includes the following increases to net expense:
•
$25 million accrued loss for a settlement in principle of a producer claim against us;
•
$23 million increase in amortization expense related to our regulatory asset associated with asset retirement obligations;
•
$20 million write-off of development costs of an abandoned project;
•
$12 million expense recognized in 2013 related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates.
Other (income) expense – net within Operating income includes the following decreases to net expense:
•
$40 million of income associated with net insurance recoveries related to the Geismar Incident in 2013;
•
$16 million of income from insurance recoveries related to the abandonment of certain of Eminence storage assets in 2013;
•
$9 million involuntary conversion gain recognized in 2013 related to a 2012 furnace fire for our Geismar olefins plant.

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 expenses.
The favorable change in Equity earnings (losses) is primarily due to higher equity earnings from Access Midstream Partners resulting from the acquisition of this investment in late 2012 and improved equity earnings from Laurel Mountain. These increases are partially offset by lower equity earnings from Discovery.
Interest expense increased due to a $42 million increase in Interest capitalized related to construction projects primarily at Williams Partners, substantially offset by a $43 million increase in Interest incurred primarily due to an increase in borrowings (see Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements).
The favorable change in Other investing income – net is primarily due to a $43 million increase in interest income associated with a receivable related to the sale of certain former Venezuela assets and gains of $31 million resulting from Access Midstream Partners' equity issuances in 2013. These increases are partially offset by the absence of $63 million of income recognized in 2012, including $10 million of interest income, related to the 2010 sale of our interest in Accroven SRL. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
Provision (benefit) for income taxes changed unfavorably primarily due to $99 million of deferred income tax expense recognized in 2013 related to the undistributed earnings of certain foreign operations that are no longer considered permanently reinvested. This is partially offset by a reduction in tax expense due to lower pre-tax income. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both years.
Income (loss) from discontinued operations in 2013 primarily includes a $15 million charge resulting from an unfavorable ruling associated with our former Alaska refinery related to the Trans-Alaska Pipeline System Quality Bank. Income (loss) from discontinued operations in 2012 primarily includes a $144 million gain on reconsolidation following the sale of certain of our former Venezuela operations. (See Note 4 – Discontinued Operations of Notes to Consolidated Financial Statements.)
The unfavorable change in Net income attributable to noncontrolling interests primarily reflects our slightly decreased percentage of limited partner ownership of WPZ and higher operating results at WPZ, partially offset by higher income allocated to the general partner associated with incentive distribution rights. It also reflects our partners’ share of increased interest income related to a receivable from the sale of certain former Venezuela assets. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
2012 vs. 2011
The increase in Service revenues is primarily due to higher fee revenues resulting from increased gathering and processing volumes in the Marcellus Shale, including new volumes from our assets acquired in the 2012 Caiman Acquisition and Laser Acquisition and higher volumes in the western deepwater Gulf of Mexico and in the Piceance basin. Additionally, natural gas transportation revenues increased from expansion projects placed into service in 2011 and 2012.
The decrease in Product sales is primarily due to lower NGL and olefin production revenues reflecting an overall decrease in average per-unit sales prices, and lower marketing revenues primarily due to significant decreases in NGL and olefin prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities.
The decrease in Product costs is primarily due to lower olefins feedstock costs reflecting a decrease in average per-unit prices and lower costs associated with the production of NGLs primarily resulting from a decrease in average natural gas prices. Marketing purchases also decreased primarily due to significantly lower average NGL prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities.

58



The increase in Operating and maintenance expenses is primarily due to increased maintenance expenses primarily associated with assets acquired in 2012 and increased employee-related benefit costs, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.
The increase in Depreciation and amortization expenses is primarily associated with assets acquired in 2012. (See Note 2 – Acquisitions, Goodwill, and Other Intangible Assets of Notes to Consolidated Financial Statements.)
The increase in SG&A is primarily due to $23 million of acquisition and transition-related costs incurred in 2012 as well as higher employee-related and information technology expenses driven by general growth within business operations. SG&A also includes $26 million of reorganization-related costs incurred in 2012 primarily relating to our engagement of a consulting firm to assist in better aligning resources to support our business strategy following the spin-off of WPX Energy, Inc (WPX) and is substantially offset by the absence of general corporate expenses related to the spin-off of WPX, which was completed on December 31, 2011.
The unfavorable change in Other (income) expense - net within Operating income (loss) primarily reflects the absence of the Gulf Liquids litigation contingency accrual reduction of $19 million in 2011. (See Note 6 – Other Income and Expenses and Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements.)
The unfavorable change in Operating income (loss) generally reflects lower NGL production and marketing margins, as well as previously described increases in Operating and maintenance expenses, Depreciation and amortization expenses, SG&A and an unfavorable change in Other (income) expense — net. Higher fee revenues and olefin production margins partially offset these decreases.
The unfavorable change in Equity earnings (losses) is primarily due to lower Laurel Mountain, Aux Sable and Discovery equity earnings primarily reflecting lower operating results of these investees and the impairment of two minor NGL processing plants at Laurel Mountain in 2012.
Interest expense decreased due to an increase in Interest capitalized related to construction projects, as well as a decrease in Interest incurred related to corporate debt retirements in December 2011, partially offset by an increase in borrowings and the absence of a $14 million reduction of an interest accrual related to a litigation contingency in 2011 as previously discussed.
The favorable change in Other investing income — net is primarily due to $63 million of income, including interest, recognized in 2012 as compared to an $11 million gain in 2011 related to the 2010 sale of our interest in Accroven SRL. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
Early debt retirement costs in 2011 reflect costs related to corporate debt retirements in December 2011, including $254 million in related premiums.
Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income, the absence of approximately $147 million tax benefit from federal settlements and an international revised assessment in 2011, and the absence of $66 million deferred tax benefit recognized in 2011 related to the undistributed earnings of certain foreign operations that we considered to be permanently reinvested. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both years.
Income (loss) from discontinued operations in 2012 primarily includes a gain on reconsolidation following the sale of certain of our former Venezuela operations. Income (loss) from discontinued operations in 2011 primarily reflects the results of operations of our former exploration and production business as discontinued operations following the spin-off of WPX. See Note 4 – Discontinued Operations of Notes to Consolidated Financial Statements for a more detailed discussion of the items in Income (loss) from discontinued operations.
The favorable change in Net income attributable to noncontrolling interests primarily reflects lower operating results at WPZ and higher income allocated to the general partner driven by incentive distribution rights, partially offset by our decreased percentage of limited partner ownership of WPZ, which was 68 percent at December 31, 2012, compared to 73 percent at December 31, 2011.

59



Year-Over-Year Operating Results – Segments
Williams Partners
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(Millions)
Segment revenues
$
6,685

 
$
7,320

 
$
7,714

Segment costs and expenses
(5,183)

 
(5,619)

 
(5,821)

Equity earnings (losses)
104

 
111

 
142

Segment profit
$
1,606

 
$
1,812

 
$
2,035

2013 vs. 2012
The decrease in segment revenues includes:
•
A $348 million decrease in revenues from our equity NGLs including $256 million due to lower volumes and a $92 million decrease associated with 10 percent lower average realized non-ethane per-unit sales prices and 44 percent lower average ethane per-unit sales prices. Equity ethane sales volumes are 81 percent lower driven by unfavorable ethane economics, as previously mentioned, and equity non-ethane volumes are 9 percent lower primarily due to a customer contract that expired in September 2013 and a change in a customer’s contract at the end of 2012 to fee-based processing, along with periods of severe winter weather conditions in the first quarter of 2013 that prevented producers from delivering gas in our western onshore operations.
•
A $312 million decrease in olefin sales due to $363 million associated with lower volumes, partially offset by $51 million associated with higher per-unit sales prices. Olefins production volumes are lower primarily due to the loss of production as a result of the Geismar Incident, an outage in a third-party storage facility which caused us to reduce production at our RGP splitter facility, and changes in inventory management. Ethylene and propylene prices averaged 21 percent and 11 percent higher, respectively, partially offset by 29 percent lower butadiene prices.
•
A $229 million decrease in marketing revenues primarily due to $244 million associated with lower NGL prices and $136 million associated with lower crude oil volumes, partially offset by $130 million related to higher non-ethane volumes primarily related to new marketing activity in our Ohio Valley Midstream business. The changes in marketing revenues are more than offset by similar changes in marketing purchases.
•
A $201 million increase in service revenues primarily includes $167 million higher fee revenues resulting from higher gathering volumes driven by new well connections related to infrastructure additions placed into service in 2012 and 2013, a full year of operations associated with gathering systems included in the 2012 acquisitions, and increased gathering rates associated with customer contract modifications primarily in the Susquehanna Supply Hub, as well as contributions from the processing and fractionation facilities placed in service in the latter half of 2012 and in 2013 in the Ohio Valley Midstream business. Natural gas transportation revenues also increased $106 million primarily due to expansion projects placed into service in 2012 and 2013, as well as new rates effective in first-quarter 2013. Partially offsetting these increases is a $43 million decrease in gathering and processing revenues primarily due to a natural decline in production volumes, primarily in the Piceance basin and Four Corners area, and severe winter weather conditions in the first quarter of 2013, which prevented producers from delivering gas in our western onshore operations. In addition, fee revenues decreased $34 million in the eastern Gulf Coast primarily driven by natural declines in Bass Lite and Blind Faith production area volumes.
•
A $53 million increase in other product sales primarily due to higher system management gas sales from our gas pipeline businesses (offset in segment costs and expenses).

60



The decrease in segment costs and expenses includes:
•
A $256 million decrease in marketing purchases primarily due to lower NGL prices and lower crude oil volumes, partially offset by higher non-ethane volumes (substantially offset in marketing revenues).
•
A $220 million decrease in olefin feedstock purchases due to $207 million associated with lower volumes, primarily due to the loss of production as a result of the Geismar Incident and the third-party storage facility outage discussed above, and $13 million lower feedstock costs, reflecting 21 percent lower average per-unit ethylene feedstock costs, partially offset by 11 percent higher average per-unit propylene feedstock costs.
•
A $51 million decrease in costs associated with our equity NGLs reflecting a $102 million decrease due to lower natural gas volumes driven by lower ethane recoveries, partially offset by a $51 million increase related to a 32 percent increase in average natural gas prices.
•
A $50 million increase in operating costs includes $42 million in higher Operating and maintenance expenses primarily associated with the businesses acquired in the Laser and Caiman Acquisitions in February and April 2012, respectively, and the subsequent growth in these operations, as well as $13 million of costs incurred under our insurance deductibles associated with the Geismar Incident. These increases are partially offset by lower compressor and pipeline maintenance and repair expenses at our Gulf Coast businesses primarily due to the absence of expenses relating to the substantial completion of a natural gas pipeline integrity management plan during 2012. Additionally, the increase in operating costs includes $44 million in higher Depreciation and amortization expenses primarily reflecting a full year of expense in 2013 associated with the businesses acquired in 2012 and depreciation on subsequent infrastructure additions, partially offset by the absence of increased depreciation in 2012 on certain assets in the Gulf Coast region resulting from a change in the estimated useful lives. Partially offsetting these increases in operating costs is lower SG&A primarily due to the absence of acquisition and transition costs of $23 million incurred in 2012.
•
A $50 million increase in other product costs primarily due to higher system management gas costs from our gas pipeline businesses (offset in segment revenues).
•
An $8 million favorable change in Other (income) expense - net primarily attributable to the recognition of $40 million of income associated with the net insurance recoveries related to the Geismar Incident during 2013 and $9 million involuntary conversion gains related to a 2012 furnace fire at our Geismar olefins plant. The favorable changes are partially offset by a $25 million accrued loss for a settlement in principle of a producer claim against us and $23 million higher amortization of regulatory assets associated with asset retirement obligations in 2013.
The decrease in segment profit includes:
•
A $297 million decrease in NGL margins driven primarily by lower NGL volumes and prices and higher natural gas prices, partially offset by lower natural gas volumes.
•
A $92 million decrease in olefin margins including $156 million associated with lower product volumes at our Geismar plant offset by $41 million higher ethylene per-unit sales prices and $21 million lower ethylene feedstock costs.
•
A $50 million increase in operating costs as previously discussed.
•
A $7 million decrease in Equity earnings (losses) primarily due to $20 million lower equity earnings from Discovery driven by lower NGL margins reflecting lower volumes including reduced ethane recoveries and natural declines, as well as lower NGL prices. In addition, charges to write-down two lateral pipelines and electrical equipment in 2013 and the absence of a favorable customer settlement in 2012 decreased equity earnings from Discovery. The decrease is partially offset by $15 million improved equity earnings from Laurel Mountain driven primarily by 55 percent higher gathering volumes, the receipt of an annual minimum volume commitment fee in 2013, and lower leased compression expenses.

61



•
A $201 million increase in service revenues as previously discussed.
•
A $27 million increase in marketing margins primarily due to favorable prices in 2013 and the absence of losses recognized in the second quarter of 2012 driven by significant declines in NGL prices while product was in transit.
•
An $8 million favorable change in Other (income) expense - net as previously discussed.
2012 vs. 2011
The decrease in segment revenues includes:
•
A $366 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $354 million associated with an overall 26 percent decrease in average NGL per-unit sales prices. Average ethane and non-ethane per-unit prices decreased by 49 percent and 15 percent, respectively.
•
A $77 million decrease in olefin sales revenues including $42 million lower ethylene production sales revenues primarily due to 10 percent lower average per-unit sales prices and $26 million lower propylene production sales revenues primarily due to 17 percent lower average per-unit sales prices.
•
Marketing revenues were $93 million lower primarily due to a significant decrease in NGL and olefin prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities.
•
A $39 million decrease in system management gas sales from our gas pipeline businesses (offset in segment costs and expenses).
•
A $203 million increase in fee revenues primarily includes $163 million higher fee revenues due to higher volumes in the Marcellus Shale, including new volumes on our gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses; higher volumes in the western deepwater Gulf of Mexico, including higher volumes on our Perdido Norte natural gas and oil pipelines; and higher volumes in the Piceance basin. It also includes a $40 million increase in transportation revenues associated with natural gas pipeline expansion projects placed in service during 2011 and 2012.
The decrease in segment costs and expenses includes:
•
A $183 million decrease in olefin feedstock costs including $130 million lower ethylene feedstock costs driven by 38 percent lower average per-unit feedstock costs and $28 million lower propylene feedstock costs primarily due to 20 percent lower per-unit feedstock costs.
•
A $137 million decrease in costs associated with our equity NGLs primarily due to a 31 percent decrease in average natural gas prices.
•
A $39 million decrease in system management gas costs from our gas pipeline businesses (offset in segment revenues).
•
A $46 million decrease in marketing purchases primarily due to significantly lower average NGL prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities. The changes in natural gas marketing purchases are more than offset by similar changes in natural gas marketing revenues.
•
A $132 million increase in operating costs including higher depreciation and amortization of assets and intangibles, along with maintenance costs associated with assets acquired in 2012, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.

62



•
An $81 million increase in general and administrative expenses including $23 million of Caiman and Laser acquisition and transition-related costs, as well as increases in employee-related and information technology expenses driven by general growth within our business operations.
The decrease in segment profit includes:
•
A $229 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices.
•
A $132 million increase in operating costs as previously discussed.
•
An $81 million increase in general and administrative expenses as previously discussed.
•
A $47 million decrease in margins related to the marketing of NGLs primarily due to the impact of a significant and rapid decline in NGL prices, primarily during the second quarter of 2012, while product was in transit and a $7 million unfavorable change in write-downs of inventories to lower of cost or market. These unfavorable variances compare to periods of increasing prices during 2011.
•
A $31 million decrease in Equity earnings (losses) primarily due to $19 million lower Laurel Mountain equity earnings driven by lower gathering rates indexed to natural gas prices, higher operating costs, including depreciation, and the impairment of two minor NGL processing plants, partially offset by higher gathered volumes; $12 million lower Aux Sable equity earnings primarily due to lower NGL margins; and $12 million lower Discovery equity earnings primarily due to lower NGL margins and volumes. These decreases are partially offset by $11 million higher Gulfstream equity earnings primarily due to WPZ’s acquisition of additional interest in Gulfstream, which was previously reflected in Other.
•
A $203 million increase in fee revenues as previously discussed.
•
A $106 million increase in olefin product margins including $88 million higher ethylene production margins primarily due to 38 percent lower average per-unit feedstock prices, partially offset by 10 percent lower average per-unit sales prices. DAC production margins were also $13 million higher, primarily resulting from higher average per-unit margins driven primarily by lower average per-unit feedstock prices.
Williams NGL & Petchem Services
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(Millions)
Segment revenues
$
273

 
$
279

 
$
341

Segment costs and expenses
(235
)
 
(180
)
 
(184
)
Segment profit
$
38

 
$
99

 
$
157

2013 vs. 2012
Segment revenues decreased primarily due to $7 million lower propylene product sales revenues primarily due to 23 percent lower sales volumes partially offset by 18 percent higher average per-unit sales prices. The lower sales volumes were due to a scheduled third-quarter 2013 shutdown to conduct maintenance and to effect the ethane recovery project tie-in, as well as the impact of delays associated with resuming production during the fourth quarter of 2013. These decreased volumes were partially offset by the absence of the impact of filling the Boreal Pipeline in June 2012.
Segment costs and expenses increased $55 million primarily due to $23 million higher Operating and maintenance expenses primarily resulting from increased maintenance related to the scheduled third-quarter 2013 shutdown, as well as a $16 million unfavorable change in Other (income) expense – net primarily due to the $20 million write-off of an abandoned project, partially offset by the favorable impact of foreign currency exchange. Additionally, Depreciation and amortization expenses increased $13 million primarily due to certain assets that were decommissioned in the third

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
$
61

 
$
—

 
$
—

2013 vs. 2012
Segment profit in 2013 includes $93 million of equity earnings recognized from Access Midstream Partners, which we acquired an interest in during December 2012. Offsetting the 2013 equity earnings is $63 million of noncash amortization of the difference between the cost of our investment and our underlying share of the net assets of Access Midstream Partners. In addition, segment profit in 2013 includes noncash gains of $31 million resulting from Access Midstream Partners’ equity issuances in 2013. These equity issuances resulted in the dilution of our ownership of limited partnership units from approximately 24 percent to 23 percent, which is accounted for as though we sold a portion of our investment.
In 2013, we received regular quarterly distributions from Access Midstream Partners totaling $93 million.
Other
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(Millions)
Segment revenues
$
36

 
$
27

 
$
25

Segment profit (loss)
(4
)
 
49

 
24

2013 vs. 2012
The unfavorable change in segment profit is primarily due to the absence of the gain of $53 million recognized in 2012 related to the 2010 sale of our interest in Accroven SRL. As part of a settlement regarding certain Venezuelan assets in the first quarter of 2012, we received payment for all outstanding balances due from this sale. (See Note 5 –

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



Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
In 2013, we continued to focus upon both growth in our businesses through disciplined investment and growth in our per-share dividends. Examples of this growth included:
•
Expansion of Williams Partners’ interstate natural gas pipeline system to meet the demand of growth markets;
•
Continued investment in Williams Partners’ gathering and processing capacity and infrastructure in the Marcellus Shale area and deepwater Gulf of Mexico, as well as expansion of our olefins business in the Gulf Coast region;
•
Expansion of our Canadian facilities and investment in a joint project to develop the Bluegrass Pipeline;
•
Total per-share dividends grew 20 percent to $1.4375 in 2013 compared to $1.19625 in 2012.
This growth was funded through cash flow from operations, distributions from WPZ and Access Midstream Partners, debt and equity offerings at WPZ, and cash on hand.
Outlook
We seek to manage our businesses with a focus on applying conservative financial policy in order to maintain investment-grade credit metrics. Our plan for 2014 reflects our ongoing transition to an overall business mix that is increasingly fee-based. Although our cash flows are impacted by fluctuations in energy commodity prices, that impact is somewhat mitigated by certain of our cash flow streams that are not directly impacted by short-term commodity price movements, including:
•
Firm demand and capacity reservation transportation revenues under long-term contracts;
•
Fee-based revenues from certain gathering and processing services.
We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, dividends and distributions, debt service payments, and tax payments, including an estimated $111 million tax payment as a result of WPZ’s expected acquisition of certain of our Canadian operations, while maintaining a sufficient level of liquidity. In particular, we note the following:
•
We expect capital and investment expenditures to total between $4.16 billion and $5.04 billion in 2014. Of this total, maintenance capital expenditures, which are generally considered nondiscretionary and include expenditures to meet legal and regulatory requirements, to maintain and/or extend the operating capacity and useful lives of our assets, and to complete certain well connections, are expected to total between $360 million and $440 million. Expansion capital expenditures, which are generally more discretionary to fund projects in order to grow our business are expected to total between $3.8 billion and $4.6 billion. See Company Outlook - Expansion Projects for discussions describing the general nature of these expenditures. In addition, we retain the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.
•
We expect to pay total cash dividends of approximately $1.75 per common share in 2014, an increase of 22 percent over 2013 levels.
•
We expect to fund working capital requirements, capital and investment expenditures, debt service payments, dividends and distributions, and tax payments primarily through cash flow from operations, cash and cash equivalents on hand, issuances of WPZ debt and/or equity securities, and utilization of our credit facility and WPZ’s credit facility and/or commercial paper program. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $2.85 billion and $3.175 billion in 2014.

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Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2014. Our internal and external sources of consolidated liquidity include cash generated from our operations, including cash distributions from WPZ and our equity method investments based on our level of ownership and incentive distribution rights, cash and cash equivalents on hand, cash proceeds from WPZ’s offerings of common units, our credit facility and WPZ’s credit facility and/or commercial paper program. Additional sources of liquidity, if needed, include bank financings, proceeds from the issuance of debt and/or equity securities, and proceeds from asset sales. These sources are available to us at the parent level and are expected to be available to certain of our subsidiaries, particularly equity and debt issuances from WPZ. WPZ is expected to be self-funding through its cash flows from operations, use of its credit facility and/or commercial paper program, and its access to capital markets.
Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include those previously discussed in Company Outlook.
As of December 31, 2013, we had a working capital deficit (current liabilities, inclusive of commercial paper borrowings, in excess of current assets) of $300 million. However, we note the following about our available liquidity.
 
 
December 31, 2013
Available Liquidity
 
WPZ
 
WMB
 
Total
 
 
(Millions)
Cash and cash equivalents
 
$
102

 
$
579

(1)
$
681

Capacity available under our $1.5 billion credit facility (expires July 31, 2018) (2)
 
 
 
1,500

 
1,500

Capacity available to WPZ under its $2.5 billion five-year credit facility (expires July 31, 2018) less amounts outstanding under its $2 billion commercial paper program (3)(4)
 
2,275

 
 
 
2,275

 
 
$
2,377

 
$
2,079

 
$
4,456

__________
(1)
Includes $278 million of Cash and cash equivalents held primarily by certain international entities, that we intend to utilize to fund growth in our Canadian midstream operations. The remainder of our Cash and cash equivalents is primarily held in government-backed instruments.

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

(3)
The highest amount outstanding during 2013 was $1.085 billion under WPZ’s commercial paper program. As of February 25, 2014, $900 million is outstanding under WPZ’s commercial paper program. At December 31, 2013, WPZ is in compliance with the financial covenants associated with the credit facility and commercial paper program. (See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.) The WPZ credit facility is only available to WPZ, Transco, and Northwest Pipeline as co-borrowers. On July 31, 2013, WPZ amended its $2.4 billion credit facility to increase the aggregate commitments to $2.5 billion and extend the maturity date to July 31, 2018. The amended credit facility, under certain circumstances, may be increased up to an additional $500 million.

(4)
In managing our available liquidity, we do not expect a maximum outstanding amount under WPZ’s commercial paper program in excess of the capacity available under WPZ’s credit facility.
In addition to the credit facilities and WPZ’s commercial paper program listed above, we have issued letters of credit totaling $16 million as of December 31, 2013, under certain bilateral bank agreements.

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As described in Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements, we have determined that we have net assets that are technically considered restricted in accordance with Rule 4-08(e) of Regulation S-X of the Securities and Exchange Commission in excess of 25 percent of our consolidated net assets. We do not expect this determination will impact our ability to pay dividends or meet future obligations as the terms of WPZ’s partnership agreement require it to make quarterly distributions of all available cash, as defined, to its unitholders.
Commercial Paper
In March 2013, WPZ initiated a commercial paper program. The program allows a maximum outstanding amount at any time of $2 billion of unsecured commercial paper notes. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. Proceeds from these notes are used for general partnership purposes, including funding capital expenditures, working capital, and partnership distributions. WPZ classifies these commercial paper notes outstanding as short-term borrowings as they have maturity dates less than three months from the date of issuance. At December 31, 2013, WPZ had $225 million in commercial paper outstanding.
Debt Offering
In November 2013, WPZ completed a public offering of $600 million of 4.5 percent senior unsecured notes due 2023 and $400 million of 5.8 percent senior unsecured notes due 2043. WPZ used the net proceeds to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes.
Distributions from Equity Method Investees
Our equity-method investees’ organizational documents require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. Our more significant equity-method investees include: Access Midstream Partners, Aux Sable, Caiman II, Discovery, Gulfstream, Laurel Mountain, and OPPL.
Shelf Registration
In April 2013, WPZ filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in WPZ having an aggregate offering price of up to $600 million. These sales will be made over a period of time and from time to time in transactions at prices which are market prices prevailing at the time of sale, prices related to market price or at negotiated prices. Such sales will be made pursuant to an equity distribution agreement between WPZ and certain banks who may act as sales agents or purchase for their own accounts as principals. As of December 31, 2013, no common units have been issued under this registration.
Equity Offerings
In August 2013, WPZ completed an equity issuance of 21,500,000 common units representing limited partner interests. Subsequently, the underwriters exercised their option to purchase 3,225,000 common units. The net proceeds of approximately $1.2 billion to WPZ were used to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes.
In March 2013, WPZ completed an equity issuance of 14,250,000 common units representing limited partner interests, including 3,000,000 common units sold to us in a private placement. Subsequently, the underwriters exercised their option to purchase 1,687,500 common units. The net proceeds of approximately $760 million to WPZ, including $143 million received from us on the private placement sale, were used to repay amounts outstanding under the WPZ credit facility.
WPZ Incentive Distribution Rights
Our ownership interest in WPZ includes the right to incentive distributions determined in accordance with WPZ’s partnership agreement. We have agreed to temporarily waive our incentive distributions through 2013 related to the common units issued by WPZ to us and the seller in connection with the Caiman Acquisition. In connection with the

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contribution of certain Gulf olefins assets to WPZ in November 2012, we also agreed to waive $16 million per quarter of incentive distributions until the later of December 31, 2013 or 30 days after the Geismar plant expansion is operational. Cash distributions to us from WPZ through the February 2014 distribution were reduced by a total of $147 million associated with these waived incentive distributions.
In May 2013, we agreed to waive additional incentive distributions of up to $200 million total through the subsequent four quarters to further support WPZ’s cash distribution metrics as its large platform of growth projects moves toward completion. Cash distributions to us from WPZ through the February 2014 distribution were reduced by a total of $90 million in association with these waived incentive distributions.
Credit Ratings
Our ability to borrow money is impacted by our credit ratings and the credit ratings of WPZ. The current ratings are as follows: 
 
 
 
 
 
 
 
 
 
Rating Agency
  
Outlook
  
Senior
Unsecured
Debt Rating
  
Corporate
Credit Rating
Williams:
 
  
 
  
 
  
 
 
 
 
 
 
 
 
 
 
Standard & Poor’s
  
Stable
  
BBB-
  
BBB
 
 
 
 
 
 
 
 
 
Moody’s Investors Service
  
Stable
  
Baa3
  
N/A
 
 
 
 
 
 
 
 
 
Fitch Ratings
  
Stable
  
BBB-
  
N/A
 
 
 
 
 
 
 
 
Williams Partners:
  
 
  
 
  
 
 
 
 
 
 
 
 
 
 
Standard & Poor’s
  
Stable
  
BBB
  
BBB
 
 
 
 
 
 
 
 
 
Moody’s Investors Service
  
Stable
  
Baa2
  
N/A
 
 
 
 
 
 
 
 
 
Fitch Ratings
  
Positive
  
BBB-
  
N/A
With respect to Standard and Poor’s, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard and Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard and Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.
With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. The “1”, “2”, and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” indicates a ranking at the lower end of the category.
With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.
Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A downgrade of our credit rating might increase our future cost of borrowing and would require us to post additional collateral with third parties, negatively impacting our available liquidity. As of December 31, 2013, we estimate that a downgrade to a rating below investment grade for us or WPZ could require us to post up to $8 million or $282 million, respectively, in additional collateral with third parties.

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Sources (Uses) of Cash
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(Millions)
Net cash provided (used) by:
 
 
 
 
 
Operating activities
$
2,217

 
$
1,835

 
$
3,439

Financing activities
1,677

 
5,036

 
(342
)
Investing activities
(4,052
)
 
(6,921
)
 
(3,003
)
Increase (decrease) in cash and cash equivalents
$
(158
)
 
$
(50
)
 
$
94