10-K 1 wmb_20151231x10k.htm 10-K 10-K
 
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, 2015
 
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 $39,345,468,396.
The number of shares outstanding of the registrant’s common stock outstanding at February 22, 2016 was 750,065,665.

DOCUMENTS INCORPORATED BY REFERENCE
None
 



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.



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DEFINITIONS

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

Measurements:
Barrel: One barrel of petroleum products that equals 42 U.S. gallons
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:
ACMP: Access Midstream Partners, L.P. prior to its merger with Pre-Merger WPZ
Cardinal: Cardinal Gas Services, L.L.C.
Constitution: Constitution Pipeline Company, LLC
Gulfstar One: Gulfstar One LLC
Jackalope: Jackalope Gas Gathering Services, L.L.C.
Pre-merger WPZ: Williams Partners L.P. prior to its merger with ACMP
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, as of December 31, 2015, we account for as an equity-method investment, including principally the following:
Aux Sable: Aux Sable Liquid Products LP
Bluegrass: Bluegrass Pipeline Company LLC
Caiman II: Caiman Energy II, LLC
Discovery: Discovery Producer Services LLC
Gulfstream: Gulfstream Natural Gas System, L.L.C.
Laurel Mountain: Laurel Mountain Midstream, LLC
Moss Lake: Moss Lake Fractionation LLC and Moss Lake LPG Terminal LLC
OPPL: Overland Pass Pipeline Company LLC
UEOM: Utica East Ohio Midstream LLC


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Government and Regulatory:
Code, the: Internal Revenue Code of 1986
EPA: Environmental Protection Agency
Exchange Act, the: Securities and Exchange Act of 1934, as amended
FERC: Federal Energy Regulatory Commission
IRS: Internal Revenue Service
SEC: Securities and Exchange Commission
Other:
Energy Transfer: Energy Transfer Equity, L.P.
ETC: Energy Transfer Corp LP
Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer and certain of its affiliates
ETC Merger: Merger wherein Williams will be merged into ETC
CCR: Contingent consideration right
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
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
MVC: Minimum volume commitment
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
PDH facility:  Propane dehydrogenation facility
RGP Splitter:  Refinery grade propylene splitter
Throughput:  The volume of product transported or passing through a pipeline, plant, terminal, or other facility


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PART I

Item 1. Business
In this report, Williams (which includes The Williams Companies, Inc. and, unless the context otherwise indicates, all of our subsidiaries) is at times referred to in the first person as “we,” “us” or “our.” We also sometimes refer to Williams as the “Company.”
WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION
We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents electronically with the SEC under the Exchange Act. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SEC’s Internet website at www.sec.gov.
Our Internet website is www.williams.com. We make available free of charge through the Investor tab of our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Code of Ethics for Senior Officers, Board committee charters and the Williams Code of Business Conduct are also available on our Internet website. We will also provide, free of charge, a copy of any of our corporate documents listed above upon written request to our Corporate Secretary, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
GENERAL
We are primarily an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to 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.
As of December 31, 2015, our interstate gas pipelines, midstream, and olefins production interests were largely held through our significant investment in Williams Partners L.P. (WPZ). We own the general partner interest and a 58 percent limited-partner interest in WPZ.
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, Utah; Houston, Texas; Oklahoma City, Oklahoma; Pittsburgh, Pennsylvania; Calgary, Alberta; and the Four Corners Area. Our telephone number is 918-573-2000.
DIVIDENDS
We increased our quarterly dividends from $0.57 per share in the fourth quarter of 2014 to $0.64 per share in the fourth quarter of 2015.
ENERGY TRANSFER MERGER AGREEMENT
On September 28, 2015, we entered into a Merger Agreement with Energy Transfer and certain of its affiliates. The Merger Agreement, subject to approval of our stockholders and certain regulatory approvals, provides that we will be merged with and into the newly formed ETC with ETC surviving the ETC Merger. Energy Transfer formed ETC as a limited partnership that will be treated as a corporation for U.S. federal income tax purposes. ETC will be publicly traded on the New York Stock Exchange under the symbol “ETC.”
At the effective time of the ETC Merger, each issued and outstanding share of our common stock (except for certain shares such as those held by us or our subsidiaries and any held by ETC and its affiliates) will be canceled and automatically converted into the right to receive stock, cash, or a combination of both, at the election of each holder


4




and subject to proration as set forth in the Merger Agreement. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies for additional information.)
FINANCIAL INFORMATION ABOUT SEGMENTS
See “Item 8 — Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — Note 19 – Segment Disclosures”.
BUSINESS SEGMENTS
Substantially all our operations are conducted through our subsidiaries. Our activities in 2015 were primarily operated through the following business segments as presented in the accompanying financial statements and management’s discussion and analysis.
Williams Partners — comprised of our consolidated master limited partnership, WPZ, which includes gas pipeline and midstream businesses. The gas pipeline business includes interstate natural gas pipelines and pipeline joint project investments. The midstream business provides natural gas gathering, treating, processing and compression 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.
Our Canadian midstream operations include an oil sands offgas processing plant near Fort McMurray, Alberta, an NGL/olefin fractionation facility, and the Boreal Pipeline.
Williams NGL & Petchem Services — comprised of our Texas Belle pipeline and certain other domestic olefins pipeline assets and certain Canadian growth projects under development, including a propane dehydrogenation facility and a liquids extraction plant.
Other — primarily comprised of corporate operations and our Canadian construction services company.
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 equity-method investment in Gulfstream and a 41 percent interest in Constitution (a consolidated entity), which is under development. Transco and Northwest Pipeline own and operate a combined total of approximately13,600 miles of pipelines with a total annual throughput of approximately 4,136 TBtu of natural gas and peak-day delivery capacity of approximately 15.4 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, which is regulated by the FERC, 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, 2015, Transco’s system had a mainline delivery capacity of approximately 6.4 MMdth of natural gas per day from its production areas to its primary markets, including delivery capacity from the mainline


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to locations on its Mobile Bay Lateral. Using its Leidy Line along with market-area storage and transportation capacity, Transco can deliver an additional 5.1MMdth of natural gas per day for a system-wide delivery capacity total of approximately 11.5 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 1.8 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, natural 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 it owns and operates. 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, 2015, Transco’s customers had stored in its facilities approximately 161 Bcf of natural gas. In addition, wholly owned subsidiaries of Transco operate and hold a 35 percent equity-method investment 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, which is regulated by the FERC, 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, either directly or indirectly through interconnections with other pipelines.
Pipeline system and customers
At December 31, 2015, Northwest Pipeline’s system, having long-term firm transportation and storage redelivery agreements with aggregate capacity reservations of approximately 3.8 MMdth/d, was composed of approximately 3,900 miles of mainline and lateral transmission pipeline 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 redelivery 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 natural gas storage services 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 natural 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 customers.
Gulfstream
Gulfstream is a 745-mile interstate natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida, which has a capacity to transport 1.3 Bcf/d. Williams Partners owns, through a subsidiary, a 50 percent equity-method investment in Gulfstream. Williams Partners shares operating responsibilities for Gulfstream with the other 50 percent owner.


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Midstream Business
Williams Partners’ midstream business, one of the nation’s largest natural gas gatherers and processors, has primary service areas concentrated in major producing basins in Arkansas, Colorado, New Mexico, Oklahoma, Texas, 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) crude 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. 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.
Key variables for this business will continue to be:
Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;
Prices impacting commodity-based activities.
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;
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 domestic 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. A portion of our fee-based processing revenues includes a share of the margins on the NGLs produced. For the year ended December 31, 2015, 76 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


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that were extracted during processing with natural gas purchases, also known as shrink replacement gas, and (4) deliver an equivalent Btu content of natural gas for customers at the plant outlet. NGLs we retain in connection with this type of processing agreement are referred to as our equity NGL production. Under these agreements, we have commodity price exposure on the difference between NGL and natural gas prices. For the year ended December 31, 2015, 20 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, 2015, 4 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. Some contracts have price escalators which annually increase our gathering rates. In addition, certain contracts include fee redetermination or cost of service mechanisms that are designed to support a return on invested capital and allow our gathering rates to be adjusted, subject to specified caps in certain cases, to account for variability in volume, capital expenditures, compression and other expenses. Our gas gathering agreements with two major customers include MVCs covering their respective producing regions. If the minimum annual or semi-annual volume commitment is not met, these customers are obligated to pay a fee equal to the applicable fee for each Mcf by which the applicable customer’s minimum annual or semi-annual volume commitment exceeds the actual volume gathered. The revenue associated with such shortfall fees is recognized in the fourth quarter of each year.
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 2015, Williams Partners’ facilities gathered and processed gas for approximately 230 customers. Williams Partners’ top six gathering and processing customers accounted for approximately 74 percent of our gathering and processing fee revenue and NGL margins from our keepwhole and percent-of-liquids agreements.
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 systems in Pennsylvania delivers residue gas volumes into Transco’s pipeline in addition to third-party interstate systems.


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The following table summarizes our significant consolidated natural gas gathering assets:
 
Natural Gas Gathering Assets
 
Location
 
Pipeline
Miles
 
Inlet
Capacity
(Bcf/d)
 
Ownership
Interest
 
Supply Basins/Shale Formations
Central
 
 
 
 
 
 
 
 
 
Barnett Shale
Texas
 
860
 
0.9
 
100%
 
Barnett Shale
Eagle Ford Shale
Texas
 
1,118
 
0.7
 
100%
 
Eagle Ford Shale
Haynesville Shale
Louisiana
 
592
 
1.7
 
100%
 
Haynesville Shale
Permian
Texas
 
346
 
0.1
 
100%
 
Permian
Mid-Continent
Arkansas, Oklahoma, Texas
 
2,112
 
0.9
 
100%
 
Miss-Lime, Granite Wash, Colony Wash
Northeast
 
 
 
 
 
 
 
 
 
Ohio Valley
West Virginia & Pennsylvania
 
210
 
0.8
 
100%
 
Appalachian
Susquehanna Supply Hub
Pennsylvania & New York
 
370
 
2.7
 
100%
 
Appalachian
Cardinal (1)
Ohio
 
349
 
1.0
 
66%
 
Appalachian
Atlantic-Gulf
 
 
 
 
 
 
 
 
 
Canyon Chief, including Blind Faith and Gulfstar extensions
Deepwater Gulf of Mexico
 
156
 
0.5
 
100%
 
Eastern Gulf of Mexico
Other Eastern Gulf
Offshore shelf and other
 
46
 
0.2
 
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
Other Western Gulf
Offshore shelf and other
 
120
 
0.9
 
100%
 
Western Gulf of Mexico
West
 
 
 
 
 
 
 
 
 
Four Corners
Colorado & New Mexico
 
3,743
 
1.8
 
100%
 
San Juan
Wamsutter
Wyoming
 
1,973
 
0.6
 
100%
 
Wamsutter
Southwest Wyoming
Wyoming
 
1,614
 
0.5
 
100%
 
Southwest Wyoming
Piceance
Colorado
 
336
 
1.5
 
(2)
 
Piceance
Niobrara
Wyoming
 
184
 
0.2
 
(3)
 
Powder River
__________
(1)
Statistics reflect 100 percent of the assets from our 66 percent ownership of Cardinal gathering system.
(2)
Includes our 60 percent ownership of a gathering system in the Ryan Gulch area with 140 miles of pipeline and 200 MMcf/d of inlet capacity, and our 67 percent ownership of a gathering system at Allen Point with 8 miles of pipeline and 60 MMcf/d of inlet capacity. We operate both systems. We own and operate 100 percent of the balance of the Piceance gathering assets.
(3)
Includes our 50 percent ownership of the Jackalope gathering system, which we operate, with 184 miles of pipeline and 165 MMcf/d of inlet capacity.


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The following table summarizes our significant consolidated natural gas processing facilities:
 
Natural Gas Processing Facilities
 
Location
 
Inlet
Capacity
(Bcf/d)
 
NGL
Production
Capacity
(Mbbls/d)
 
Ownership
Interest
 
Supply Basins
Northeast
 
 
 
 
 
 
 
 
 
Fort Beeler
Marshall County, WV
 
0.5
 
62
 
100%
 
Appalachian
Oak Grove
Marshall County, WV
 
0.2
 
25
 
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
West
 
 
 
 
 
 
 
 
 
Echo Springs
Echo Springs, WY
 
0.7
 
58
 
100%
 
Wamsutter
Opal
Opal, WY
 
1.1
 
47
 
100%
 
Southwest Wyoming
Willow Creek
Rio Blanco County, CO
 
0.5
 
30
 
100%
 
Piceance
Ignacio
Ignacio, CO
 
0.5
 
29
 
100%
 
San Juan
Kutz
Bloomfield, NM
 
0.2
 
12
 
100%
 
San Juan
Bucking Horse (1)
Converse County, WY
 
0.1
 
7
 
50%
 
Powder River
Parachute
Garfield County, CO
 
1.2
 
6
 
100%
 
Piceance
__________
(1)
Statistics reflect 100 percent of the assets from our 50 percent ownership of Bucking Horse gas processing facility.
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.
We also own and operate fractionation facilities at Moundsville, de-ethanization and condensate facilities at our Oak Grove processing plant, another condensate stabilization facility near our Oak Grove plant, and an ethane transportation pipeline.  Our two condensate stabilizers are capable of handling more than 14 Mbbls/d of field condensate.  NGLs are extracted from the natural gas stream in our cryogenic processing plants. Our Oak Grove de-ethanizer is capable of handling up to approximately 80 Mbbls/d of mixed NGLs to extract up to approximately 40 Mbbls/d of ethane.  The remaining mixed NGL stream from the de-ethanizer is then transported and fractionated at our Moundsville facilities, which are capable of handling more than 42 Mbbls/d of mixed NGLs.  Ethane produced at our de-ethanizer is transported to markets via our 50-mile ethane pipeline from Oak Grove to Houston, Pennsylvania.
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. Fixed fees associated with the resident production at our Gulfstar One facility are recognized as the guaranteed capacity is made available. 


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The following tables summarize our significant crude oil transportation pipelines and production handling platforms:
 
Crude Oil Pipelines
 
Pipeline
Miles
 
Capacity
(Mbbls/d)
 
Ownership
Interest
 
Supply Basins
Mountaineer, including Blind Faith and Gulfstar extensions
172
 
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
Gulfstar I FPS (1)
172
 
80
 
51%
 
Eastern Gulf of Mexico
__________
(1)
Statistics reflect 100 percent of the assets from our 51 percent interest in Gulfstar One.

Canadian Operations
Our Canadian operations include an oil sands offgas processing plant located near Fort McMurray, Alberta, and an NGL/olefin fractionation facility located at Redwater, Alberta, which is near Edmonton, Alberta, and the Boreal Pipeline which transports NGLs and associated 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 whereby a portion of the profit 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), iso-butane, alky feedstock, 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 26 Mbbls/d of olefin and NGL products. Our Redwater fractionator has a liquids handling capacity of 26 Mbbls/d. 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.
Operating Statistics
The following table summarizes our significant operating statistics:
 
2015
 
2014
 
2013
Volumes:
 
 
 
 
 
Canadian propylene sales (millions of pounds)
161

 
143

 
118

Canadian NGL sales (millions of gallons)
284

 
218

 
123



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Gulf Olefins
We have an 88.5 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.
In 2015, we placed in service an expansion of the olefins production facility that increased its ethylene production capacity by 600 million pounds per year, for a total production capacity of 1.95 billion pounds of ethylene and 114 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. Following an explosion and fire that occurred in 2013, the Geismar plant resumed consistent operations in late March 2015 and reached full production capacity in the third quarter of 2015.
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, the majority of sales are based on supply contracts of one year or less in duration.
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 in central Kansas near Conway. These assets include a 50 percent interest in an NGL fractionation facility with capacity of slightly more than 100 Mbbls/d and we own approximately 20 million barrels of NGL storage capacity.
We own approximately 115 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.  A portion of these pipelines are leased to third parties.
We own the roughly 280-mile Bayou Ethane Pipeline, which operates between Texas and Louisiana. The pipeline connects a 57-mile pipeline segment from Mont Belvieu to Port Arthur, Texas, and a 50-mile pipeline segment from Lake Charles, Louisiana, to Port Arthur. The pipeline provides ethane transportation capacity from fractionation and storage facilities in Mont Belvieu, Texas, to the WPZ Geismar olefins plant in south Louisiana and serves customers along the way.   


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We also own a 14.6 percent equity-method investment 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 107 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
Effective January 1, 2016, WPZ organizes these businesses into the following operating areas:
Central is comprised of domestic gathering, treating, and compression services to producers under long-term, fixed fee contracts. Its primary operating areas are in the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian basins. Central also includes a 50 percent equity-method investment in the Delaware basin gas gathering system in the Permian region.
Northeast G&P is comprised of natural gas gathering and processing and NGL fractionation businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virgina and the Utica Shale region of eastern Ohio, as well as a 62 percent equity-method investment in UEOM, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, and Appalachia Midstream Services, LLC, which owns an approximate average 45 percent equity-method investment in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
Atlantic-Gulf is comprised of an interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated entity) which is a proprietary floating production system, as well as a 50 percent equity-method investment in Gulfstream, a 41 percent interest in Constitution (a consolidated entity) which is under development, and a 60 percent equity-method investment in Discovery.
West is comprised of the natural gas gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming and an interstate natural gas pipeline, Northwest Pipeline.
NGL & Petchem Services is comprised of our 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and various petrochemical and feedstock pipelines in the Gulf Coast region, an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility. This segment also includes an NGL and natural gas marketing business, storage facilities and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL.
Certain Equity-Method Investments
Discovery
We own a 60  percent 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 a 614-mile offshore natural gas gathering and transportation system in the Gulf of Mexico with an inlet capacity of 1,350 MMcf/d, including the Keathley Canyon Connector, a 209-mile deepwater lateral pipeline in the central deepwater Gulf of Mexico that contributed 400 MMcf/d of inlet capacity when it was placed in service in late 2014. Discovery’s assets also include a crude oil production handling platform with a crude oil/NGL handling capacity of 10 Mbbls/d and natural gas processing capacity of 75 MMcf/d.
Laurel Mountain
We own a 69 percent interest in a joint venture, Laurel Mountain, that includes a 2,053-mile gathering system that we operate in western Pennsylvania with the capacity to gather 0.7 Bcf/d of natural gas. 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.


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Caiman II
We own a 58 percent interest in Caiman II, which owns a 50 percent interest in Blue Racer, a joint project to own, operate, develop and acquire midstream assets in the Utica Shale and certain adjacent areas in the Marcellus Shale. Blue Racer’s assets include 688 miles of natural gas gathering pipelines, including 422 miles of large-diameter pipelines, the Natrium complex in Marshall County, West Virginia, with a cryogenic processing capacity of 400 MMcf/d and fractionation capacity of approximately 123,000 Bbls/d, the Berne complex in Monroe County, Ohio, with a cryogenic processing capacity of 400 MMcf/d, and NGL and condensate pipelines connecting Natrium to Berne.
Overland Pass Pipeline
We own and operate a 50 percent 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.
Delaware Basin Gas Gathering System
We own a non-operated 50 percent interest in the Delaware basin gas gathering system in the Permian region. The system is comprised of 403 miles of gathering pipeline, located in west Texas.
Utica East Ohio Midstream
We own a 62 percent interest in UEOM, a joint project to develop infrastructure for the gathering, processing and fractionation of natural gas and NGLs in the Utica Shale play in Eastern Ohio. We, along with other equity owners, operate the infrastructure complex which consists of natural gas gathering and compression facilities, four processing plants with a total capacity of 800 MMcf per day, 41 Mbbls/d of condensate stabilization capacity, a 135 Mbbls/d NGL fractionation facility, approximately 950,000 barrels of NGL storage capacity and other ancillary assets, including loading and terminal facilities that are operated by our partner. These assets earn a fixed fee that escalates annually within a specified range.
Appalachia Midstream    
Through our wholly owned subsidiary Appalachia Midstream, we operate 100 percent of and own an approximate average 45 percent interest in multiple natural gas gathering systems that consist of approximately 970 miles of gathering pipeline in the Marcellus Shale region. The majority of our volumes in the region are gathered from northern Pennsylvania, southwestern Pennsylvania and the northwestern panhandle of West Virginia in core areas of the Marcellus Shale. Appalachia Midstream operates the assets under long-term, 100 percent fixed-fee gathering agreements that include significant acreage dedications and cost of service mechanisms.
Operating Statistics
The following table summarizes our significant operating statistics for Williams Partners’ midstream business:
 
2015
 
2014
 
2013
Volumes: (1)
 
 
 
 
 
Gathering (Tbtu)
3,298

 
2,482

 
1,731

Plant inlet natural gas (Tbtu)
1,448

 
1,419

 
1,549

NGL production (Mbbls/d) (2)
130

 
128

 
143

NGL equity sales (Mbbls/d) (2)
31

 
27

 
40

Crude oil transportation (Mbbls/d) (2)
126

 
105

 
117

Geismar ethylene sales (millions of pounds)
1,066

 

 
467

__________
(1)
Excludes volumes associated with equity-method investments.
(2)
Annual average Mbbls/d.


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Williams NGL & Petchem Services
The Williams NGL & Petchem Services segment is comprised of our Texas Belle pipeline and certain other domestic olefins pipeline assets and certain Canadian growth projects under development, including a propane dehydrogenation facility and a liquids extraction plant. As this segment is currently comprised primarily of projects under development, reported revenues to-date are nominal.
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:
 
Total
 
(Millions)
2015
 
Service:


Regulated natural gas transportation & storage
$
1,938

Gathering, processing, and production handling
2,804

 
 
2014
 
Service:
 
Regulated natural gas transportation & storage
$
1,781

Gathering, processing, and production handling
1,838

 
 
2013
 
Service:
 
Regulated natural gas transportation & storage
$
1,704

Gathering, processing and production handling
966

We have one customer, Chesapeake Energy Corporation, and its affiliates, that accounts for 18 percent of our total revenue. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for additional details.)

REGULATORY MATTERS
FERC
Our 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, our rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement or abandonment of our jurisdictional facilities, among other things, are subject to regulation. Each gas pipeline company holds certificates


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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.
We also own interests in and operate 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
Our 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 Pipeline and Hazardous Materials Safety Administration (PHMSA) administers federal pipeline safety laws.
Federal pipeline safety laws authorize PHMSA 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. PHMSA 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, PHMSA performs pipeline safety inspections and has the authority to initiate enforcement actions.
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, PHMSA 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 PHMSA 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.


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On January 3, 2012, the Pipeline Safety Act was enacted. The Pipeline Safety Act requires PHMSA 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 for both gas and liquid pipeline systems. PHMSA 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 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. Ongoing periodic reassessments and initial assessments of any new high consequence areas have been completed. We estimate that the cost to be incurred in 2016 associated with this program to be approximately $68 million. 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 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 be incurred in 2016 associated with this program will be approximately $8 million. 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 and New York actively regulate gathering activities. Texas regulates gathering primarily through complaint mechanisms under which the state commission may resolve disputes involving an individual gathering arrangement. New York has specific regulations pertaining to the design, construction and operations of gathering lines in New York.
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
Our 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.


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Canadian Operations
Our Canadian assets are regulated by the Alberta Energy Regulator (AER) and we also have certain facilities that are regulated by the Alberta Environment and Parks (AEP). The two agencies, AER and AEP, include 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 18 – Contingent Liabilities and Commitments of our Notes to Consolidated Financial Statements for further details on our regulatory matters. For additional information regarding regulatory matters, please also refer to “Risk Factors — 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,” “- 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;" and "- 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."
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 that could exceed current expectations,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental” and “Environmental Matters” in Note 18 – Contingent Liabilities and Commitments of our Notes to Consolidated Financial Statements.


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COMPETITION
Gas Pipeline Business
The natural gas industry has a highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity. 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.
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.
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. In addition, LDCs are entering the long haul transportation business through joint venture pipelines.
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.
Midstream Business
Generally, our gathering and processing agreements are long-term agreements that may include acreage dedication. We primarily face competition to the extent these agreements approach renewal or new volume opportunities arise. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies. 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.
Ethylene and propylene markets, and therefore our olefins business, compete in a worldwide marketplace. At Geismar, we currently benefit from the lower cost natural gas based feedstocks 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.
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. The sales of our NGL and olefin products compete in the worldwide marketplace.
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 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.” 


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EMPLOYEES
At February 1, 2016, we had approximately 6,578 full-time employees.
FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS
See Note 19 – 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 19 – 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

The reports, filings and other public announcements of The Williams Companies, Inc. (Williams) may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 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:
The status, expected timing and expected outcome of the proposed ETC Merger;
Statements regarding the proposed ETC Merger;
Our beliefs relating to value creation as a result of the proposed ETC Merger;
Benefits and synergies of the proposed ETC Merger;
Future opportunities for the combined company;
Other statements regarding Williams’ and Energy Transfer’s future beliefs, expectations, plans, intentions, financial condition or performance;
Expected levels of cash distributions by Williams Partners L.P. (WPZ) with respect to general partner interests, incentive distribution rights and limited partner interests;
Levels of dividends to Williams stockholders;
Future credit ratings of Williams and WPZ;
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;
Seasonality of certain business components;


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Natural gas, natural gas liquids, and olefins prices, supply, 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:
Satisfaction of the conditions to the completion of the proposed ETC Merger, including receipt of the approval of Williams’ stockholders;
The timing and likelihood of completion of the proposed ETC Merger, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals for the proposed merger that could reduce anticipated benefits or cause the parties to abandon the proposed transaction;
The possibility that the expected synergies and value creation from the proposed ETC Merger will not be realized or will not be realized within the expected time period;
The risk that the businesses of Williams and Energy Transfer will not be integrated successfully;
Disruption from the proposed ETC Merger making it more difficult to maintain business and operational relationships;
The risk that unexpected costs will be incurred in connection with the proposed ETC Merger;
The possibility that the proposed ETC Merger does not close, including due to the failure to satisfy the closing conditions;
Whether WPZ will produce sufficient cash flows to provide the level of cash distributions we expect;
Whether Williams is able 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 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;
Our 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 developmental 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;
Williams’ costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
Changes in maintenance and construction costs;


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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 debt agreements, future changes in credit ratings as determined by nationally-recognized credit rating agencies 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 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.
The pendency of the proposed ETC Merger could adversely affect our business and operations.
In connection with the proposed ETC Merger, some of our customers or vendors may delay or defer decisions, which could negatively impact our revenues, earnings, cash flows and expenses, regardless of whether the proposed ETC Merger is completed. Similarly, our current and prospective employees may experience uncertainty about their future roles following the proposed ETC Merger, which may materially adversely affect our ability to attract and retain key personnel during the pendency of the proposed ETC Merger. If we fail to complete the proposed ETC Merger, it may be difficult and expensive to recruit and hire replacements for departed employees. The proposed ETC Merger, its effects and related matters may also distract our employees from day-to-day operations and require substantial commitments of time and resources. In addition, due to operating covenants in the Merger Agreement, we may be unable, during the pendency of the proposed ETC Merger, to pursue certain strategic transactions, undertake certain significant capital projects, undertake certain significant financing transactions and otherwise pursue other actions that are not in the ordinary course of business. Such risks relating to vendors, customers, employees and those risks arising from operating covenants in the Merger Agreement will also apply to varying degrees to our subsidiaries and affiliates and thereby have a corresponding impact on us.
There can be no assurance when or even if the proposed ETC Merger will be completed.
Completion of the proposed ETC Merger is subject to the satisfaction or waiver of a number of conditions that must be satisfied or waived, including approval of the proposed ETC Merger by our stockholders, the expiration or termination of the waiting period applicable to the proposed ETC Merger under antitrust laws, the absence of any law


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or order prohibiting the closing of the proposed ETC Merger, the declaration by the SEC of the effectiveness of the registration statement on Form S-4 of which the proxy statement/prospectus forms a part and the authorization of the listing on the NYSE of the ETC common shares. There can be no assurance that we, ETC, and Energy Transfer will be able to satisfy the closing conditions or that closing conditions beyond their or our control will be satisfied or waived. Completion of the proposed ETC Merger is also conditioned on the accuracy of representations and warranties made by the parties to the Merger Agreement (subject to customary materiality qualifiers and other customary exceptions) and the performance in all material respects by the parties of obligations imposed under the Merger Agreement.We and Energy Transfer can mutually agree at any time to terminate the Merger Agreement, even if our stockholders have already voted to approve the Merger Agreement. We and Energy Transfer can also terminate the Merger Agreement under other specified circumstances.
If the proposed ETC Merger is not completed, we will be subject to a number of risks, including the following:
Because the current price of shares of our common stock may reflect a market premium based on the assumption that we will complete the proposed ETC Merger, a failure to complete the proposed ETC Merger could result in a decline in the price of shares of our common stock;
In specified circumstances, we may be required to pay Energy Transfer a termination fee of $1.48 billion and certain of their expenses;
We will not realize the benefits expected from being part of a larger combined organization;
We have incurred and expect to continue incurring a number of non-recurring ETC Merger-related expenses that must be paid even if the proposed ETC Merger is not completed.
In addition, if the proposed ETC Merger is not completed, we may experience negative reactions from the financial markets and from our customers and employees. We also could be subject to litigation related to any failure to complete the proposed ETC Merger or to proceedings commenced against us to attempt to force us to perform our obligations under the Merger Agreement.
The Merger Agreement contains provisions that could discourage a potential competing acquirer of us or could result in any competing proposal being at a lower price than it might otherwise be.
The Merger Agreement contains provisions that, subject to certain exceptions, restrict our ability to solicit, encourage, facilitate or discuss competing third-party proposals to acquire all or a significant part of us. In addition, Energy Transfer will have an opportunity to negotiate with us in response to any competing proposal that may be made before our board of directors is permitted to withdraw or qualify its recommendation. In some circumstances, upon termination of the Merger Agreement, we may be required to pay to Energy Transfer a termination fee of $1.48 billion.
These provisions could discourage a potential competing acquirer that might have an interest in acquiring all or a significant part of us from considering or proposing that acquisition, even if it were prepared to pay consideration with a higher value than the consideration proposed to be received or realized in the proposed ETC Merger, or might result in a potential competing acquirer proposing to pay a lower price than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances.
The integration of our business following the proposed ETC Merger will involve considerable risks and may not be successful.
Achieving the anticipated benefits of the proposed ETC Merger will depend in part upon whether Energy Transfer can integrate our businesses in an effective and efficient manner. Energy Transfer may not be able to accomplish this integration process successfully. The integration of any business may be complex and time-consuming. The difficulties that could be encountered include the following:
Integrating personnel, operations and systems;
Coordinating the geographically dispersed organizations;


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Distraction of management and employees from operations changes in corporate culture;
Retaining existing customers and attracting new customers;
Maintaining business relationships; and
Inefficiencies associated with the integration of the operations of ETC.
In addition, there will be integration costs and non-recurring transaction costs associated with the proposed ETC Merger (such as fees paid to legal, financial, accounting and other advisors and other fees paid in connection with the proposed ETC Merger) and achieving the expected cost savings and synergies associated therewith, and such costs may be significant.
An inability to realize the full extent of the anticipated benefits of the proposed ETC Merger, as well as any delays encountered in the integration process and the realization of such benefits, could have an adverse effect upon the revenues, level of expenses and operating results of Energy Transfer, which may adversely affect the value of Energy Transfer common units and, in turn, the value of ETC common shares after the completion of the merger.
Stockholder litigation could prevent or delay the closing of the proposed ETC Merger or otherwise negatively impact our business and operations.
We have incurred and may continue to incur additional costs in connection with the defense or settlement of the currently pending and any future stockholder litigation in connection with the proposed ETC Merger. Such litigation may adversely affect our ability to complete the proposed ETC Merger and could also have an adverse effect on our financial condition and results of operations.
We are exposed to the credit risk of our customers and counterparties, including Chesapeake Energy Corporation and its affiliates, and our credit risk management will not be able to completely eliminate 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 will not completely 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. The current low commodity price environment has, in particular, negatively impacted natural gas producers causing them significant economic stress including, in some cases, to file for bankruptcy protection or to renegotiate contracts.To the extent one or more of our key customers commences bankruptcy proceedings, our contracts with the customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code, or may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could have a material adverse effect on our business, results of operations, cash flows and financial conditions. For example, Chesapeake Energy Corporation and its affiliates, which accounted for approximately 18 percent of our 2015 consolidated revenues, have experienced significant, negative financial results due to sustained low commodity prices. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties or otherwise do not take or are unable to take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts receivable. 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.

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


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Our revenues, operating results, future rate of growth and the value of certain components of our businesses depend primarily upon the prices of NGLs, olefins, natural gas, oil or other commodities, and the differences between prices of these commodities, and could be materially adversely affected by an extended period of current low commodity prices or a further decline in commodity prices. Price volatility has and could continue to 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 has and could continue to 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.
Downgrades of our credit ratings, which are determined outside of our control by independent third parties, impact our liquidity, access to capital and our costs of doing business.
Our credit ratings have recently been downgraded. Downgrades of our credit ratings 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 continue to be limited by the downgrading of our credit ratings.
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. As of the date of the filing of this report, we have been assigned sub investment-grade credit ratings by each of the three ratings agencies.
Our ability to obtain credit in the future could be affected by WPZ’s credit ratings.
A substantial portion of our operations are conducted through, and our cash flows are substantially derived from distributions paid to us by, WPZ. Due to our relationship with WPZ, our ability to obtain credit will be affected by WPZ’s credit ratings. WPZ’s credit ratings have recently been downgraded. If WPZ were to experience a further deterioration in its credit standing or financial condition, our access to capital and our ratings could be further adversely affected. Any future downgrading of a WPZ credit rating could also result in a further downgrading of our credit rating. A downgrading of a WPZ credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.


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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. We do not obtain independent evaluations of natural gas and NGL reserves connected to our systems and processing facilities. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. 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 have both a project lifecycle process and an investment evaluation process. These are processes we use to identify, evaluate and execute on acquisition opportunities and capital projects. We may not always 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;


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Acquisitions and capital projects may require substantial new capital, including 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 generally 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. As of December 31, 2015, our investments in the Partially Owned Entities accounted for approximately 8 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 expected or any dividends.
We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash we dividend may fluctuate from quarter to quarter and will depend on various factors, some of which are beyond our control, including:
The amount of cash that WPZ and our other subsidiaries 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;
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 currently our largest cash-generating asset. Therefore, we are, at the least, indirectly exposed to all the risks to which WPZ is subject and 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.
We may not be able to sell assets or, if we are able to sell assets, to raise a sufficient amount of capital from such asset sales. In addition, the timing to enter into and close any asset sales could be significantly different than our expected timeline.
In addition to the recent announcement that WPZ plans to monetize assets during 2016 to fund capital and investment expenditures, it is possible that we could also engage in asset sales. Given the commodity markets, financial markets and other challenges currently facing the energy sector, our competitors may also engage in asset sales leading to lower demand for the assets we wish to sell. We may not be able to sell the assets we identify for sale on favorable terms or at all. If we are able to sell assets, the timing of the receipt of the asset sale proceeds may not align with the timing of our capital requirements. A failure to raise sufficient capital from asset sales or a misalignment of the timing of capital raised and capital funding needs could have an adverse impact on our business, financial condition, results of operations and cash flows.


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An impairment of our assets, including goodwill, property, plant and equipment, intangible assets, and/or equity-method investments, could reduce our earnings.
GAAP requires us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. If the current depressed energy commodity price environment persists for a prolonged period or further declines, such circumstances could result in additional impairments of our assets beyond those incurred in 2015 including impairments of our goodwill, property, plant and equipment, intangible assets, and/or equity method investments. Additionally any asset monetization could result in impairments if any assets are sold for amounts less than their carrying value. If we determine that an impairment has occurred, we would be required to take an immediate noncash charge to earnings.
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, add additional customers, or otherwise increase the contracted volumes of natural gas provided to us by current producers, in each case on favorable terms, if at all, our financial condition, growth plans, and the amount of cash available to pay dividends could be adversely affected. Our ability to replace, extend, or add additional customer or supplier contracts, or increase contracted volumes of natural gas from current producers, 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 negatively impact our ability to maintain or achieve favorable contractual terms, including pricing, and could also 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;
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.


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Some of our businesses, including WPZ’s Central business, are exposed to supplier concentration risks arising from dependence on a single or a limited number of suppliers.
Some of our businesses may be dependent on a small number of suppliers for delivery of critical goods or services. For instance, pursuant to a compression services agreement, WPZ’s Central business receives a substantial portion of its compression capacity on certain gathering systems from EXLP Operating LLC (“Exterran Operating”). Exterran Operating has, until December 31, 2020, the exclusive right to provide WPZ’s Central business with compression services on certain gas gathering systems located in Wyoming, Texas, Oklahoma, Louisiana, and Arkansas, in return for the payment of specified monthly rates for the services provided, subject to an annual escalation provision. If a supplier on which one of our businesses depends were to fail to timely supply required goods and services such business may not be able to replace such goods and services in a timely manner or otherwise on favorable terms or at all. If our business is unable to adequately diversify or otherwise mitigate such supplier concentration risks and such risks were realized, such businesses could be subject to reduced revenues and increased expenses, which could have a material adverse effect on our financial condition, results of operation and cash flows.
We will conduct certain operations through joint ventures that may limit our operational flexibility or require us to make additional capital contributions.
Some of our operations are conducted through joint venture arrangements, and we may enter additional joint ventures in the future. In a joint venture arrangement, we have less operational flexibility, as actions must be taken in accordance with the applicable governing provisions of the joint venture. In certain cases we:
Have limited ability to influence or control certain day to day activities affecting the operations;
Cannot control the amount of capital expenditures that we are required to fund with respect to these operations;
Are dependent on third parties to fund their required share of capital expenditures;
May be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets;
May be forced to offer rights of participation to other joint venture participants in the area of mutual interest.
In addition, joint venture participants may have obligations that are important to the success of the joint venture, such as the obligation to pay substantial carried costs pertaining to the joint venture and to pay their share of capital and other costs of the joint venture. The performance and ability of third parties to satisfy their obligations under joint venture arrangements is outside our control. If these third parties do not satisfy their obligations under these arrangements, our business may be adversely affected. Joint venture partners may be in a position to take actions contrary to instructions or requests or contrary to our policies or objectives, and disputes between us and our joint venture partners may result in delays, litigation or operational impasses.
If we fail to make a required capital contribution under the applicable governing provisions of a joint venture arrangements, we could be deemed to be in default under the joint venture agreement. Joint venture partners may be permitted to fund any deficiency resulting from our failure to make such capital contribution, which would result in a dilution of our ownership interest, or such joint venture partners may have the option to purchase all of our existing interest in the subject joint venture.
The risks described above or the failure to continue joint ventures, or to resolve disagreements with joint venture partners could adversely affect our ability to conduct our operation that is the subject of a joint venture, which could in turn negatively affect our financial condition and results of operations.
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, the processing of olefins, and crude oil transportation and production handling, including:


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Aging infrastructure and mechanical problems;
Damages to pipelines and pipeline blockages or other pipeline interruptions;
Uncontrolled releases of natural gas (including sour gas), NGLs, olefins products, brine or industrial chemicals;
Collapse or failure of storage caverns;
Operator error;
Damage caused by third-party activity, such as operation of construction equipment;
Pollution and other environmental risks;
Fires, explosions, craterings and blowouts;
Truck and rail loading and unloading;
Operating in a marine environment.
Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, loss of services to our customers, reputational damage and substantial losses to us. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. An event such as those described above could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.
We do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.
In accordance with customary industry practice, we maintain insurance against some, but not all, risks and losses, and only at levels we believe to be appropriate. We currently maintain excess liability insurance with limits of $820 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 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.
Our assets and operations, as well as our customers’ assets and operations, can be adversely affected by weather and other natural phenomena.


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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 could also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information.
Breaches in our information technology infrastructure or physical facilities, or other disruptions including those arising from theft, vandalism, fraud or unethical conduct, could result in damage to our assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.
The natural gas sales, transportation and storage operations of our gas pipelines are subject to regulation by the FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines, including a reasonable rate of return.
In addition to regulation by other federal, state and local regulatory authorities, under the Natural Gas Act of 1938, interstate pipeline transportation and storage service is subject to regulation by the FERC. Federal regulation extends to such matters as:
Transportation and sale for resale of natural gas in interstate commerce;
Rates, operating terms, types of services and conditions of service;
Certification and construction of new interstate pipelines and storage facilities;
Acquisition, extension, disposition or abandonment of existing interstate pipelines and storage facilities;
Accounts and records;
Depreciation and amortization policies;


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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 the 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 and construction activities. 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 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 Environmental Protection Agency 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


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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.
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 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, including those pertaining to oil and gas hedging and cash collateral requirements, might be adopted or become applicable to us, our customers or our business activities. 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.


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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 periodically been affected by concerns over U.S. fiscal and monetary policies. 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.
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, 2015, was $23.99 billion.
The agreements governing our indebtedness contain covenants that restrict our and our material subsidiaries’ ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets in certain circumstances. 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;
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


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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, please read Note 14 – Debt, Banking Arrangements, and Leases.
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 several 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.
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 contractual obligations with respect to WPZ as the general partner and to the limited partners of WPZ. Activities determined to involve such 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 such 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


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could make it more difficult to obtain nonrecourse project financing or other financing on suitable terms, could adversely affect the ability of certain customers to honor their obligations with respect to such projects or investments and could impair our ability to enforce our rights under agreements relating to such projects or investments.
Operations and investments in foreign countries also can present currency exchange rate and convertibility, inflation and repatriation risk. In certain situations under which we develop or acquire projects or make investments, economic and monetary conditions and other factors could affect our ability to convert to U.S. dollars our earnings denominated in foreign currencies. In addition, risk from fluctuations in currency exchange rates can arise when our foreign subsidiaries expend or borrow funds in one type of currency, but receive revenue in another. In such cases, an adverse change in exchange rates can reduce our ability to meet expenses, including debt service obligations. We may or may not put contracts in place designed to mitigate our foreign currency exchange risks. We have some exposures that are not hedged and which could result in losses or volatility in our results of operations.
Failure of our service providers or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.
Certain of our accounting and information technology services are currently provided by third-party vendors, and sometimes from service centers outside of the United States. Services 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. Our reliance on others as service providers could have a material adverse effect on our business, results of operations and financial condition.
The execution of the integration strategy following WPZ’s merger with Access Midstream Partners, L.P. (“ACMP”) in February 2015 (the “ACMP Merger”) may not be successful.
The ultimate success of the ACMP Merger will depend, in part, on the ability of the combined company to realize the anticipated benefits from combining these formerly separate businesses. Realizing the benefits of the ACMP Merger will depend in part on the effective integration of assets, operations, functions and personnel while maintaining adequate focus on our core businesses. Any expected cost savings, economies of scale, enhanced liquidity or other operational efficiencies, as well as revenue enhancement opportunities, or other synergies, may not occur.
If management is unable to minimize the potential disruption of our ongoing business and the distraction of management during the integration process, the anticipated benefits of the ACMP Merger may not be realized or may only be realized to a lesser extent than expected. In addition, the inability to successfully manage the integration could have an adverse effect on us.
The integration process could result in the loss of key employees, as well as the disruption of each of our ongoing businesses or the creation of inconsistencies in standards, controls, procedures and policies. Any or all of those occurrences could adversely affect our businesses’ ability to maintain relationships with service providers, customers and employees or to achieve the anticipated benefits of the ACMP Merger. Integration may also result in additional and unforeseen expenses, which could reduce the anticipated benefits of the ACMP Merger and materially and adversely affect our business, operating results and financial condition.
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.
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.


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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.
Increases in interest rates could adversely impact our share price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash dividends at our intended levels.
Interest rates may increase further in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our share price will be impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on our share price and our ability to issue equity or incur debt for acquisitions or other purposes and to pay cash dividends at our intended levels.
Item 1B. Unresolved Staff Comments
Not applicable.
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


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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 November 2013, we became aware of deficiencies with the air permit for the Fort Beeler gas processing facility located in West Virginia.  We notified the EPA and the West Virginia Department of Environmental Protection and are working to bring the Fort Beeler facility into full compliance.  At December 31, 2015, we have accrued liabilities of $140,000 for potential penalties arising out of the deficiencies.
On January 21, 2016, we received a Compliance Order from the Pennsylvania Department of Environmental Protection requiring the correction of several alleged deficiencies arising out of the construction of the Springville Gathering Line, the Pennsylvania Mainline Gathering Line, and the 2008 Core Zone Gathering Line. The Order also identifies civil penalties in the amount of approximately $712,000. We are currently evaluating the Order and our response.
Other
The additional information called for by this item is provided in Note 18 – Contingent Liabilities and Commitments of the Notes to Consolidated Financial Statements included under Part II, Item 8. Financial Statements of this report, which information is incorporated by reference into this item.
Item 4. Mine Safety Disclosures
Not applicable.



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Executive Officers of the Registrant
The name, age, period of service, and title of each of our executive officers as of February 26, 2016, are listed below. As previously discussed, Williams Partners L.P. merged with ACMP in February 2015 (the ACMP Merger). ACMP was the surviving entity in the ACMP Merger and changed its name to Williams Partners L.P. References in the biographical information below to (a) “Pre-merger WPZ” will mean Williams Partners L.P. prior to the ACMP Merger and (b) “ACMP/WPZ” will refer to both ACMP prior to and after the ACMP Merger, when it changed its name to Williams Partners L.P.
Alan S. Armstrong
Director, Chief Executive Officer, and President
 
Age: 53
 
Position held since 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. Mr.  Armstrong has served as a director of the general partner of ACMP/WPZ since 2012, as Chief Executive Officer since December 31, 2014, and as Chairman of the Board since February 2, 2015. Mr. Armstrong has served as a director of BOK Financial Corporation, a financial services company, since 2013. Mr. Armstrong also served as Chairman of the Board and Chief Executive Officer of the general partner of Pre-merger WPZ from 2011 until the ACMP Merger, as Senior Vice President - Midstream from 2010 to 2011, and director and Chief Operating Officer from 2005 to 2010.
Walter J. Bennett
Senior Vice President — West
 
Age: 46
 
Position held since January 2015.
 
Mr. Bennett was formerly Chief Operating Officer of Chesapeake Midstream Development and served as Senior Vice President-Operations at Boardwalk Pipeline Partners. Previously, Mr. Bennett served in a variety of senior positions at Gulf South Pipeline Company that included operations and commercial responsibilities. Mr. Bennett began his career at a subsidiary of Koch Industries. Mr. Bennett has served as Senior Vice President - West of the general partner of ACMP/WPZ since December 2013 and served as Senior Vice President - West of the general partner of Pre-merger WPZ from January 2015 until the ACMP Merger.


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Francis (Frank) E. Billings
Senior Vice President — Corporate Strategic Development
 
Age: 53
 
Position held since January 2014.
 
Mr. Billings served as Senior Vice President - Northeast G&P of us and Pre-merger WPZ 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 one of our subsidiaries in 1998, serving in various management roles, including in 2008 as a Vice President in the midstream business. Mr. Billings served as Senior Vice President - Corporate Strategic Development of the general partner of Pre-merger WPZ from January 2014 until the ACMP Merger. He has served as a director of the general partner of ACMP/WPZ since February 2014 and as Senior Vice President - Corporate Strategic Development since the ACMP Merger.

Donald R. Chappel
Senior Vice President and Chief Financial Officer
 
Age: 64
 
Position held since 2003.
 
Prior to joining us, Mr. Chappel held various financial, administrative and operational leadership positions. Mr. Chappel has served as a director of the general partner of ACMP/WPZ since 2012 and as Chief Financial Officer of the general partner of ACMP/WPZ since December 31, 2014. Mr. Chappel has also served as a member of the Management Committee of Northwest Pipeline since 2007. Mr. Chappel served as Chief Financial Officer and a director of the general partner of Pre-merger WPZ from 2005 until the ACMP Merger. Mr. Chappel was Chief Financial Officer from 2007 and a director from 2008 of the general partner of Williams Pipeline Partners L.P. (WMZ), until its merger with Pre-merger WPZ in 2010. Mr. Chappel is a director of SUPERVALU, Inc. (a grocery and pharmacy company).
John R. Dearborn
Senior Vice President — NGL & Petchem Services
 
Age: 58
 
Position held since 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. 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 served as Senior Vice President - NGL & Petchem Services of the general partner of Pre-merger WPZ from 2013 until the ACMP Merger and has served in that role for the general partner of ACMP/WPZ since the ACMP Merger.


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Robyn L. Ewing
Senior Vice President and Chief Administrative Officer
 
Age: 60
 
Position held since 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: 55
 
Position held since 2013.
 
From 2011 until 2013, Mr. Miller was Senior Vice President - Midstream of Williams and the general partner of Pre-merger WPZ, acting as President of Williams’ midstream business. Mr. Miller was a Vice President of Williams’ midstream business from 2004 until 2011. Mr. Miller served as a director and Senior Vice-President - Atlantic-Gulf of the general partner of Pre-merger WPZ from 2011 until the ACMP Merger and has served in those roles for the general partner of ACMP/WPZ since the ACMP Merger. Mr. Miller has also served as a member of the Management Committee of Transco, since 2013.
Sarah C. Miller
Senior Vice President, General Counsel, and Secretary
 
Age: 44
 
Position held since 2015.
 
Ms. Miller joined Williams in 2000, where she has served in a variety of legal leadership positions, including Vice President, Corporate Secretary and Assistant General Counsel for the company’s corporate secretary team, Senior Counsel for the company’s midstream business, and as Senior Attorney for the legal department’s business development team. She was named Senior Vice President and General Counsel on June 20, 2015. Prior to joining Williams, Ms. Miller was a litigation associate at Crowe & Dunlevy.
Fred E. Pace
Senior Vice President — E&C (Engineering and Construction)
 
Age: 54
 
Position held since 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 served as Senior Vice President - E&C of the general partner of Pre-merger WPZ from 2013 until the ACMP Merger and has served in that role for the general partner of Pre-merger WPZ since the ACMP Merger.


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Brian L. Perilloux
Senior Vice President — Operational Excellence
 
Age: 54
 
Position held since 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 served as Senior Vice President - Operational Excellence of the general partner of Pre-merger WPZ from 2013 until the ACMP Merger and has served in that role for the general partner of ACMP/WPZ since the ACMP Merger.
Robert S. Purgason
Senior Vice President — Central
 
Age: 59
 
Position held since January 2015.
 
Mr. Purgason has served as a director of the general partner of ACMP/WPZ since 2012 and as Senior Vice President-Access of the general partner of ACMP/WPZ since the ACMP Merger. Mr. Purgason served as Chief Operating Officer of the general partner of ACMP/WPZ from 2010 until the ACMP Merger. Prior to joining the general partner of ACMP/WPZ, Mr. Purgason spent five years at Crosstex Energy Services, L.P. and was promoted to Senior Vice President - Chief Operating Officer in 2006. Prior to Crosstex, Mr. Purgason spent 19 years with us in various senior business development and operational roles. Mr. Purgason began his career at Perry Gas Companies in Odessa, Texas working in all facets of the natural gas treating business. Mr. Purgason has also served on the Board of Directors of L.B. Foster Company (a manufacturer, fabricator, and distributor of products and services for the rail, construction, energy, and utility markets) since December 2014.
James E. Scheel
Senior Vice President — Northeast G&P
 
Age: 51
 
Position held since January 2014.
 
From 2012 to 2014, Mr. Scheel served as Senior Vice President - Corporate Strategic Development of us and the general partner of Pre-merger WPZ. 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. Mr. Scheel has served as a director and Senior Vice President - Northeast G&P of the general partner of ACMP/WPZ since the ACMP Merger, having previously served as a director of the general partner of ACMP/WPZ from 2012 to February 2014. Mr. Scheel served as a director of the general partner of Pre-merger WPZ from 2012 until the ACMP Merger.


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John D. Seldenrust
Senior Vice President — E&C (Engineering & Construction)
 
Age: 51
 
Position held since July 2015.
 
Mr. Seldenrust served as Senior Vice President - Eastern Operations for us from January 2015 to July 2015, and for ACMP/WPZ from 2013 to July 2015. Mr. Seldenrust also previously served in a variety of operations and engineering leadership roles at ACMP and Chesapeake Energy from 2004 to August 2013. Prior to joining Chesapeake, Mr. Seldenrust held reservoir, production and facilities engineering positions with ARCO Oil & Gas, Vastar Resources and BP America.
Ted T. Timmermans
Vice President, Controller, and Chief Accounting Officer
 
Age: 59
 
Position held since 2005.
 
Mr. Timmermans served as Assistant Controller of Williams from 1998 to 2005. Mr. Timmermans served as Vice President, Controller & Chief Accounting Officer of the general partner of Pre-merger WPZ until the ACMP Merger and has served in those roles for the general partner of ACMP/WPZ since the ACMP Merger. Mr. Timmermans served as Chief Accounting Officer of the general partner of WMZ from 2008 until its merger with Pre-merger WPZ in 2010.




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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the New York Stock Exchange under the symbol “WMB.” At the close of business on February 16, 2016, we had approximately 7,754 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
2015
 
 
 
 
 
First Quarter
$
51.15

 
$
40.07

 
$
0.58

Second Quarter
61.38

 
46.28

 
0.59

Third Quarter
58.77

 
34.64

 
0.64

Fourth Quarter
44.51

 
20.95

 
0.64

2014
 
 
 
 
 
First Quarter
$
42.94

 
$
37.77

 
$
0.4025

Second Quarter
59.68

 
39.31

 
0.425

Third Quarter
59.77

 
54.28

 
0.56

Fourth Quarter
57.00

 
41.21

 
0.57

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, 2011. The Bloomberg U.S. Pipeline Index is composed of Columbia Pipeline Group, Inc., Enbridge, Inc., Inter Pipeline Ltd., Kinder Morgan, Inc., ONEOK, Inc., Pembina Pipeline Corp, Plains GP Holdings LP, Spectra Energy Corp, TransCanada Corp., and Williams. The graph below assumes an investment of $100 at the beginning of the period.

 
2010
 
2011
 
2012
 
2013
 
2014
 
2015
The Williams Companies, Inc.
100.0
 
137.1
 
172.9
 
211.9
 
256.9
 
156.6
S&P 500 Index
100.0
 
102.1
 
118.4
 
156.6
 
178.0
 
180.5
Bloomberg U.S. Pipelines Index
100.0
 
137.9
 
156.4
 
173.6
 
203.1
 
112.3


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Item 6. Selected Financial Data
The following financial data at December 31, 2015 and 2014, and for each of the three years in the period ended December 31, 2015, 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.
 
2015
 
2014
 
2013
 
2012
 
2011
 
(Millions, except per-share amounts)
Revenues (1)
$
7,360

 
$
7,637

 
$
6,860

 
$
7,486

 
$
7,930

Income (loss) from continuing operations (2)
(1,314
)
 
2,335

 
679

 
929

 
1,078

Amounts attributable to The Williams Companies, Inc.:
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations (2)
(571
)
 
2,110

 
441

 
723

 
803

Diluted earnings (loss) per common share:
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations (2)
(.76
)
 
2.91

 
.64

 
1.15

 
1.34

Total assets at December 31 (3) (4) (6)
49,020

 
50,455

 
27,065

 
24,248

 
16,432

Commercial paper and long-term debt due within one year at December 31 (5)
675

 
802

 
226

 
1

 
352

Long-term debt at December 31 (3) (4) (6)
23,812

 
20,780

 
11,276

 
10,656

 
8,300

Stockholders’ equity at December 31 (3) (4)
6,148

 
8,777

 
4,864

 
4,752

 
1,296

Cash dividends declared per common share
2.450

 
1.958

 
1.438

 
1.196

 
.78

_________
(1)
Revenues for 2014 increased reflecting the consolidation of ACMP beginning in third quarter and new Canadian construction management services.
(2)
Income (loss) from continuing operations:
For 2015 includes a $1.4 billion impairment of certain equity-method investments and a $1.1 billion impairment of goodwill;
For 2014 includes $2.5 billion pretax gain recognized as a result of remeasuring to fair value the equity-method investment we held before we acquired a controlling interest in ACMP, $246 million of insurance recoveries related to the 2013 Geismar Incident, and $154 million of cash received related to a contingency settlement. 2014 also includes $78 million of pretax equity losses from Bluegrass Pipeline and Moss Lake related primarily to the underlying write-off of previously capitalized project development costs and $76 million of pretax acquisition, merger, and transition expenses related to our acquisition of ACMP;
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;
For 2011 includes $271 million of pretax early debt retirement costs.
(3)
The increases in 2014 reflect assets acquired and debt assumed primarily related to our acquisition of ACMP (see Note 2 – Acquisitions) in third quarter as well as $1.9 billion of related debt issuances and $2.8 billion of debt issuances at WPZ. Additionally, we issued $3.4 billion of equity (see Note 14 – Debt, Banking Arrangements, and Leases and Note 15 – Stockholders' Equity).
(4)
The increases in 2012 reflect assets and investments acquired, primarily related to the Caiman and Laser Acquisitions and our investment in ACMP, as well as debt and equity issuances.
(5)
The increases in 2015, 2014, and 2013 reflects borrowings under WPZ’s commercial paper program, which was initiated in 2013.
(6)
Amounts for 2014 and preceding periods presented have been adjusted to reflect the early adoption of ASU 2015-03 and ASU 2015-15, which address the presentation of debt issuance costs (see Note 14 – Debt, Banking Arrangements, and Leases).


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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas, NGLs, and olefins. Our operations are located principally in the United States, but span from the deepwater Gulf of Mexico to the Canadian oil sands, and are organized into the Williams Partners and Williams NGL & Petchem Services reportable segments. All remaining business activities are included in Other.
Williams Partners
Williams Partners consists of our consolidated master limited partnership, WPZ, which includes gas pipeline and midstream businesses. The gas pipeline businesses include interstate natural gas pipelines and pipeline joint project investments; and the midstream businesses provide 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. As of December 31, 2015, we own approximately 60 percent of the interests in WPZ, including the interests of the general partner which are wholly owned by us, and IDRs.
Williams Partners' gas pipeline businesses consist primarily of Transco and Northwest Pipeline. Our gas pipeline businesses also hold interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent equity-method investment in Gulfstream and a 41 percent interest in Constitution (a consolidated entity), which is under development. As of December 31, 2015, Transco and Northwest Pipeline own and operate a combined total of approximately 13,600 miles of pipelines with a total annual throughput of approximately 4,136 TBtu of natural gas and peak-day delivery capacity of approximately 15 MMdth of natural gas.
Williams Partners' midstream businesses primarily consist of (1) natural gas gathering, treating, and processing; (2) NGL fractionation, storage and transportation; (3) crude oil transportation; and (4) olefins production. The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio which include the Marcellus and Utica shale plays as well as the Eagle Ford, Haynesville, Barnett, Mid-Continent, and Niobrara areas.
The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in UEOM, a 50 percent equity-method investment in the Delaware basin gas gathering system in the Mid-Continent region, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC, a 58 percent equity-method investment in Caiman Energy II, LLC, a 60 percent equity-method investment in Discovery Producer Services LLC, a 50 percent equity-method investment in Overland Pass Pipeline, LLC, and Appalachia Midstream Services, LLC, which owns an approximate average 45 percent equity-method investment in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
The midstream businesses also include our Canadian midstream operations which are comprised of an oil sands offgas processing plant near Fort McMurray, Alberta and NGL/olefin fractionation facility at Redwater, Alberta, and the Boreal Pipeline.
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 investing in growing markets, including the deepwater Gulf of Mexico, the Marcellus Shale, the Gulf Coast Region, the Canadian oil sands, 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


47




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 is comprised of our Texas Belle pipeline and certain other domestic olefins pipeline assets and certain Canadian growth projects under development, including a propane dehydrogenation facility and a liquids extraction plant. The Williams NGL & Petchem Services segment is currently comprised primarily of projects under development and thus have had limited operating revenues to date.
Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report.
Dividends
In December 2015, we paid a regular quarterly dividend of $0.64 per share, which was 12 percent higher than the same period last year.
Overview
Income (loss) from continuing operations attributable to The Williams Companies, Inc., for the year ended December 31, 2015, decreased $2.68 billion compared to the year ended December 31, 2014, primarily due to the absence of a $2.5 billion gain as a result of remeasuring our previous equity-method investment in ACMP to fair value, impairment charges associated with certain goodwill, equity-method investments, and other assets (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk), declines in NGL margins driven by 65 percent lower prices, higher depreciation expense caused by significant projects that have gone into service in 2014 and 2015, a gain of $154 million resulting from cash proceeds received for a contingency settlement in 2014, as well as increased interest expense associated with new debt issuances. These decreases were partially offset by new fee-based revenue associated with certain growth projects that were placed in service in 2014 and 2015 and the absence of equity losses in 2014 associated with the discontinuance of the Bluegrass Pipeline project. See additional discussion in Results of Operations.
Energy Transfer Merger Agreement
On September 28, 2015, we entered into an Agreement and Plan of Merger (Merger Agreement) with Energy Transfer Equity, L.P. (Energy Transfer) and certain of its affiliates. The Merger Agreement provides that, subject to the satisfaction of customary closing conditions, we will be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger), with ETC surviving the ETC Merger. Energy Transfer formed ETC as a limited partnership that will be treated as a corporation for U.S. federal income tax purposes. Upon completion of the ETC Merger, ETC will be publicly traded on the New York Stock Exchange under the symbol “ETC.”
At the effective time of the ETC Merger, each issued and outstanding share of our common stock (except for certain shares such as those held by us or our subsidiaries and any held by ETC and its affiliates) will be canceled and automatically converted into the right to receive stock, cash, or a combination thereof as described in Note 1 of Notes to Consolidated Financial Statements.
In connection with the ETC Merger, Energy Transfer will subscribe for a number of ETC common shares at the transaction price, in exchange for the amount of cash needed by ETC to fund the cash portion of the Merger Consideration (the Parent Cash Deposit), and, as a result, based on the number of shares of Williams common stock outstanding as of the date thereof, will own approximately 19 percent of the outstanding ETC common shares immediately after the effective time of the ETC Merger.


48




Immediately following the completion of the ETC Merger and of the LE GP, LLC (the general partner for Energy Transfer) merger with and into Energy Transfer Equity GP, LLC, ETC will contribute to Energy Transfer all of the assets and liabilities of Williams in exchange for the issuance by Energy Transfer to ETC of a number of Energy Transfer Class E common units equal to the number of ETC common shares issued to our stockholders in the ETC Merger plus the number of ETC common shares issued to Energy Transfer in consideration for the Parent Cash Deposit (such contribution, together with the ETC Merger and the other transactions contemplated by the Merger Agreement, the Merger Transactions).
To address potential uncertainty as to how the newly listed ETC common shares, as a new security, will trade relative to Energy Transfer common units, each ETC common share issued in the ETC Merger, as well as the ETC common shares issued to Energy Transfer in connection with the Parent Cash Deposit, will have attached to it one contingent consideration right (CCR). The terms of the CCRs are fully described in the form of CCR Agreement attached to the Merger Agreement as Exhibit H to Exhibit 2.1 of our Current Report on Form 8-K dated September 29, 2015.
The receipt of the Merger Consideration is expected to be tax-free to our stockholders, except with respect to any cash consideration received.
We expect the transaction to close in the first half of 2016. Completion of the Merger Transactions is subject to the satisfaction or waiver of a number of customary closing conditions as set forth in the Merger Agreement, including approval of the ETC Merger by our stockholders, receipt of required regulatory approvals in connection with the Merger Transactions, including the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and effectiveness of a registration statement on Form S-4 registering the ETC common shares (and attached CCRs) to be issued in connection with the Merger Transactions.
ETC filed its initial Form S-4 registration statement on November 24, 2015, and Amendment No. 1 to Form S-4 on January 12, 2016. On December 14, 2015, we and Energy Transfer issued a joint press release announcing the entry into a timing agreement with the United States Federal Trade Commission (FTC) pursuant to which both parties have agreed not to consummate ETC’s proposed acquisition of us until after the later of (i) 60 days after substantial compliance with the FTC’s request for additional information and documentary material and (ii) March 18, 2016.
Termination of WPZ Merger Agreement
On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby we would have acquired all of the publicly held outstanding common units of WPZ in exchange for shares of our common stock (WPZ Merger Agreement).
On September 28, 2015, prior to our entry into the Merger Agreement, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we are required to pay a $428 million termination fee to WPZ, of which we currently own approximately 60 percent, including the interests of the general partner and IDRs. Such termination fee will settle through a reduction of quarterly incentive distributions we are entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The distributions from WPZ in November 2015 and February 2016 were each reduced by $209 million related to this termination fee.
Williams Partners
ACMP Merger
We owned an equity-method investment in ACMP until July 1, 2014, at which time we acquired all of the interests in ACMP held by Global Infrastructure Partners II (GIP) which included 50 percent of the general partner interest and 55.1 million limited partner units for $5.995 billion in cash (ACMP Acquisition).
On October 26, 2014, we announced that our consolidated master limited partnerships Pre-merger WPZ and ACMP entered into a merger agreement and on February 2, 2015, the merger was completed (ACMP Merger). The merged partnership is named Williams Partners L.P. Under the terms of the merger agreement, each ACMP unitholder received


49




1.06152 ACMP units for each ACMP unit owned immediately prior to the ACMP Merger. In conjunction with the ACMP Merger, each Pre-merger WPZ common unit held by the public was exchanged for 0.86672 ACMP common units. Each WPZ common unit held by us was exchanged for 0.80036 ACMP common units. Prior to the closing of the ACMP Merger, the Class D limited partner units of Pre-merger WPZ, all of which were held by us, were converted into common units on a one-for-one basis pursuant to the terms of the Pre-merger WPZ partnership agreement.  Following the ACMP Merger, we own an approximate 60 percent interest in the merged partnership, including the general partner interest and incentive distribution rights.
Geismar Incident and plant expansion
On June 13, 2013, an explosion and fire occurred at Williams Partners’ Geismar olefins plant. The incident rendered the facility temporarily inoperable (Geismar Incident).
Our total property damage and business interruption loss exceeded our $500 million policy limit. Since June 2013, we have settled claims associated with $480 million of available property damage and business interruption coverage for a total of $422 million. This total includes $126 million which we received in the second quarter of 2015. The remaining insurance limits total approximately $20 million and we are vigorously pursuing collection.
Leidy Southeast
In January 2016, Leidy Southeast was placed into service, which expands Transco’s 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 west central Alabama. In March 2015, we began providing firm transportation service through the mainline portion of the project on an interim basis until the in-service date of the project as a whole. We placed the remainder of the project into service during January 2016 increasing capacity by 525 Mdth/d.
Utica and Haynesville gas gathering agreements
In September 2015, Williams announced an expansion of gas gathering services for a certain major producer customer in dry gas production areas of the Utica Shale in eastern Ohio and a consolidation of contracts in the Haynesville Shale in northwestern Louisiana.
In the Utica, WPZ executed a long-term fee-based contract that extends the length of certain acreage dedication to 2035, increases the area of dedication from 140,000 acres to 190,000 net acres and converts the cost-of-service mechanism to a fixed-fee structure with minimum volume commitments (MVCs).
A new Haynesville contract consolidates the Springridge and Mansfield contracts into a single agreement with a fixed-fee structure and extends the contract term to 2035. The consolidated contract is supported by MVCs and a drilling commitment to turn 140 equivalent wells online before the end of 2017.
Virginia Southside
In September 2015, Transco’s Virginia Southside expansion from New Jersey to a power station in Virginia and delivery points in North Carolina was placed into service. On December 1, 2014, we placed a portion of the project into service, which enabled us to begin providing 250 Mdth/d of additional firm transportation service through the mainline portion of the project on an interim basis, until the in-service date of the project as a whole.  We placed the remainder of the project into service in September 2015.  In total, the project increased capacity by 270 Mdth/d.
Northeast Connector
In May 2015, the Northeast Connector project was placed into service, which increased firm transportation capacity by 100 Mdth/d from Transco’s Station 195 in southeastern Pennsylvania to the Rockaway Delivery Lateral.


50




Rockaway Delivery Lateral
In May 2015, Transco’s Rockaway Delivery Lateral expansion between Transco’s transmission pipeline and the National Grid distribution system was placed in service, which enabled us to begin providing 647 Mdth/d of additional firm transportation service to a distribution system in New York.
Mobile Bay South III
In April 2015, Transco’s Mobile Bay South III expansion south from Station 85 in west central Alabama to delivery points along the Mobile Bay line was placed into service, which enabled us to begin providing 225 Mdth/d of additional firm transportation service on the Mobile Bay Lateral.
Bucking Horse gas processing facility
The Bucking Horse gas processing plant (Bucking Horse) began operating in February 2015. Bucking Horse is located in Converse County, Wyoming, and adds 120 MMcf/d of processing capacity in the Powder River basin Niobrara Shale play. Processed volumes at Bucking Horse have continued to increase throughout 2015 as existing rich gas production was re-directed from other third-party processing facilities. Bucking Horse has led to higher gathering volumes in 2015 as previously curtailed production has increased due to the additional processing capability.
Eagle Ford gathering system
In May 2015, WPZ acquired a gathering system comprised of approximately 140 miles of pipeline and a sour gas compression facility capable of handling up to 100 MMcf/d in the Eagle Ford shale for $112 million. The acquisition is contributing approximately 20 MMcf/d to the existing Eagle Ford throughput of approximately 400 MMcf/d.
UEOM
In June 2015, WPZ acquired an approximate 13 percent equity interest in UEOM for approximately $357 million, increasing our ownership from 49 percent to approximately 62 percent.
Volatile commodity prices
NGL margins were approximately 59 percent lower in 2015 compared to 2014 driven primarily by 58 percent lower non-ethane prices partially offset by lower natural gas feedstock prices.
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 margin volatility and NGL production and sales volumes, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.



51




The potential impact of commodity price volatility on our business is further discussed in the following Company Outlook.
Williams NGL & Petchem Services
Texas Belle Pipeline
In March 2015, the Texas Belle Pipeline (Texas Belle) went into service in the Houston Ship Channel area. Texas Belle is a 32-mile open access, service focused pipeline that transports NGLs and was designed to deliver butanes and natural gasolines from Mont Belvieu, Texas, to new demand in the Houston Ship Channel area.
Company Outlook
As previously discussed, we entered into a Merger Agreement with Energy Transfer and certain of its affiliates and expect the ETC Merger to close in the first half of 2016. The following discussion reflects our operating plan for 2016.
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 continue to maintain a strong commitment to safety, environmental stewardship, operational excellence and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our shareholders.
This strategy remains intact and we continue to execute on infrastructure projects that serve long-term natural gas needs. We expect commodity prices to remain challenged and costs of capital to remain sharply higher throughout


52




2016 as compared to 2015. Anticipating these conditions, our business plan for 2016 includes significant reductions in capital investment and expenses from our previous plans. In addition, we expect proceeds from planned asset monetizations in excess of $1 billion during 2016.
Our growth capital and investment expenditures in 2016 are expected to total $2.2 billion, which is a $1.5 billion reduction from our previous plans. Approximately $1.3 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining non-interstate pipeline growth capital spending in 2016 primarily reflects investment in gathering and processing systems limited to known new producer volumes, including wells drilled and completed awaiting connecting infrastructure. We also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.
Fee-based businesses are a significant component of our portfolio, which serves to somewhat reduce the influence of commodity price fluctuations on our operating results and cash flows. However, producer activities are being impacted by lower energy commodity prices which will reduce our gathering volumes. The credit profiles of certain of our producer customers are increasingly challenged by the current market conditions, which ultimately may result in a further reduction of our gathering volumes. Such reductions as well as further or prolonged declines in energy commodity prices may result in noncash impairments of our assets.
Commodity margins are highly dependent upon regional supply/demand balances of natural gas as they relate to NGL margins, while olefins are impacted by global supply and demand fundamentals. We anticipate the following trends in energy commodity prices in 2016, compared to 2015 that may impact our operating results and cash flows:
Natural gas and ethane prices are expected to be lower.
Non-ethane prices, including propane, are expected to be lower.
Olefins prices, including propylene, ethylene, and the overall ethylene crack spread, are expected to be lower.
In 2016, we anticipate our operating results will reflect increases from our fee-based businesses primarily as a result of Transco projects placed in service in 2015 and those anticipated to be placed in service in 2016, increases in our olefins volumes associated with a full year of operations at our Geismar plant following its 2015 repair and expansion, and anticipated lower general and administrative costs.  Additionally, we anticipate these improvements will be partially offset by the absence of operating results associated with certain asset monetizations, lower NGL margins, and additional operating expenses associated with growth projects placed in service in 2015 and those anticipated to be placed in service in 2016.
Potential risks and obstacles that could impact the execution of our plan include:
Further downgrades of our credit ratings and associated increase in cost of borrowings;
Higher cost of capital and/or limited availability of capital due to a change in our financial condition, interest rates, market or industry conditions;
Counterparty credit and performance risk, including that of Chesapeake Energy Corporation and its affiliates;
Inability to execute or delay in completing planned asset monetizations;
Delay in capturing planned cost reductions;
Lower than anticipated energy commodity prices and margins;
Decreased volumes from third parties served by our midstream business;
Unexpected significant increases in capital expenditures or delays in capital project execution;


53




Lower than expected distributions, including IDRs, from WPZ;
General economic, financial markets, or further industry downturn;
Lower than expected levels of cash flow from operations;
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 maintaining a strong financial position and liquidity, as well as through managing a diversified portfolio of energy infrastructure assets which continue to serve key markets and basins in North America.
Expansion Projects
Our ongoing major expansion projects include the following:
Williams Partners
Access Midstream Projects
We plan to expand our gathering infrastructure in the Eagle Ford, Utica, and Marcellus shale regions in order to meet our customers’ production plans. The expansion of the gathering infrastructure includes the addition of new facilities, well connections, and gathering pipeline to the existing systems.
Oak Grove Expansion
We plan to expand our processing capacity at our Oak Grove facility by adding a second 200MMcf/d cryogenic natural gas processing plant, which, based on our customers’ needs, is expected to be placed into service in 2019.
Susquehanna Supply Hub
We will continue to expand the gathering system in the Susquehanna Supply Hub in northeastern Pennsylvania that is needed to meet our customers’ production plans. The expansion of the gathering infrastructure includes additional compression and gathering pipeline to the existing system.
Atlantic Sunrise
In March 2015, we filed an application with the FERC to expand Transco’s existing natural gas transmission system along with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in west central Alabama.  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.
Constitution Pipeline
In December 2014, we received approval from the FERC to construct and operate the jointly owned Constitution pipeline. We also received a Notice of Complete Application from the New York Department of Environmental Conservation (NYDEC) in December 2014, but we continue to seek issuance of Clean Water Act Section 401 certification by the NYDEC. We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will be the operator of Constitution. The 124-mile Constitution pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We plan to place the project into service in the fourth quarter of 2016, assuming timely receipt of all necessary regulatory approvals, with an expected capacity of 650 Mdth/d.


54




Rock Springs
In March 2015, we received approval from the FERC to expand Transco’s existing natural gas transmission system from New Jersey to a proposed generation facility in Maryland. The project is planned to be placed into service in third quarter 2016 and is expected to increase capacity by 192 Mdth/d.
Hillabee
In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. We may seek rehearing of certain aspects of the FERC order. The Hillabee Expansion Project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to a proposed new interconnection with Sabal Trail Transmission's system in Alabama. The project will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail Transmission. We plan to place the initial phases of the project into service during the second quarters of 2017 and 2020, assuming timely receipt of all necessary regulatory approvals, and together they are expected to increase capacity by 1,025 Mdth/d.
Gulf Trace
In October 2015, we received approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 65 in St. Helena Parish, Louisiana westward to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana. We plan to place the project into service during the first quarter of 2017, assuming timely receipt of all other necessary regulatory approvals, and it is expected to increase capacity by 1,200 Mdth/d.
Dalton
In March 2015, we filed an application with the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey to markets in northwest Georgia. We plan to place the project into service in 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 448 Mdth/d.
Garden State
In February 2015, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 210 in New Jersey to a new interconnection on our Trenton Woodbury Lateral in New Jersey. The project will be constructed in phases and is expected to increase capacity by 180 Mdth/d. We plan to place the initial phase of the project into service during the fourth quarter of 2016 and the remaining portion in the third quarter of 2017, assuming timely receipt of all necessary regulatory approvals.
Virginia Southside II
In March 2015, we filed an application with the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from New Jersey and Virginia to a new lateral extending from our Brunswick Lateral in Virginia. We plan to place the project into service during the fourth quarter of 2017, assuming timely receipt of all necessary regulatory approvals, and expect it to increase capacity by 250 Mdth/d.
New York Bay
In July 2015, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Pennsylvania to the Rockaway Delivery Lateral transfer point and the Narrows meter station in Richmond County, New York. We plan to place the project into service during the fourth quarter of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 115 Mdth/d.


55




Redwater Expansion
As part of a long-term agreement to provide gas processing services to a second bitumen upgrader in Canada’s oil sands near Fort McMurray, Alberta, we are increasing the capacity of the Redwater facilities where NGL/olefins mixtures will be fractionated into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate. This capacity increase is expected to be placed into service during the first quarter of 2016.
Williams NGL & Petchem Services
Canadian PDH Facility
We are developing a project to construct a PDH facility in Alberta that will significantly increase production of polymer-grade propylene. The new PDH facility would produce approximately 1.1 billion pounds annually. Due to our current capital allocation considerations, in the first quarter of 2016, management determined to substantially slow the pace of development activities, limit further investment, and proceed with a strategy that could result in the potential sale of this project, entering into a partnership to fund additional development, or deferring development of the project.
Canadian NGL Infrastructure Expansion
As part of a long-term agreement to provide gas processing to a second bitumen upgrader in Canada’s oil sands near Fort McMurray, Alberta, we are building a new liquids extraction plant and an extension of the Boreal Pipeline, owned by our Williams Partners segment. The extension will enable transportation of the NGL/olefins mixture on the Boreal pipeline from the new liquids extraction plant to the expanded Redwater facilities, owned by our Williams Partners segment. We plan to place the new liquids extraction plant and interconnection with Boreal into service during the first quarter of 2016, and expect initial NGL/olefins recoveries of approximately 12 Mbbls/d. To mitigate ethane price risk associated with our processing services, we have a long-term agreement with a minimum price for ethane sales to a third-party customer.
Gulf Coast NGL and Olefin Infrastructure Expansion
Certain previously acquired liquids pipelines in the Gulf Coast region 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 purity natural gas liquids and olefins products in the Gulf Coast region. In response to the current conditions in the midstream industry, we are slowing the pace of development and may seek partners for these projects.
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We have reviewed the selection, application, and disclosure of these critical accounting estimates with our Audit Committee. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.
Pension and Postretirement Obligations
We have employee benefit plans that include pension and other postretirement benefits. Net periodic benefit cost and obligations for these plans are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute cost and the benefit obligations are shown in Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements.


56




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
$
(9
)
 
$
11

 
$
(130
)
 
$
154

Expected long-term rate of return on plan assets
(13
)
 
13

 

 

Rate of compensation increase
3

 
(2
)
 
9

 
(7
)
Other postretirement benefits:
 
 
 
 
 
 
 
Discount rate
1

 
2

 
(21
)
 
26

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

 

 

Assumed health care cost trend rate
1

 
(1
)
 
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 include 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 are 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 2015, the benefit plans’ assets outperformed their respective benchmarks for non-U.S. equity and fixed income strategies, but underperformed the respective benchmark for U.S. equity strategies. While the 2015 investment performance was less 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 6.38 percent in 2015. The 2015 actual return on plan assets for our pension plans was a loss of approximately 1.0 percent. The 10-year average rate of return on pension plan assets through December 2015 was approximately 4.4 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 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 – General, 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 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.


57




Goodwill
As disclosed within the Critical Accounting Estimates discussion in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Form 10-Q dated October 29, 2015, we performed an interim impairment evaluation of the goodwill associated with the Access Midstream reporting unit as of September 30, 2015. The goodwill associated with this reporting unit was initially recorded during the third quarter of 2014 in conjunction with our acquisition of ACMP. At September 30, 2015, the fair value of this reporting unit, determined using an income approach, exceeded the carrying value and thus no impairment was recorded. For such a measurement, the book basis of the reporting unit was reduced by the associated deferred tax liabilities. We disclosed that the evaluation utilized a discount rate of approximately 9.4 percent.
On October 1, 2015, we performed our annual review of the goodwill within the Northeast G&P and West reporting units. At that date, the fair value of each reporting unit exceeded the carrying value and no impairment was recorded. The discount rates utilized for the reporting units at October 1, 2015, were approximately 10.8 percent and 9.6 percent, respectively.
During the fourth quarter of 2015, we observed a significant decline in the market values of WPZ and comparable midstream companies within the industry. This served to reduce our estimate of enterprise value and increased our estimates of discount rates. As a result, we performed an impairment assessment of the goodwill associated with all of our reporting units as of December 31, 2015. Prior to this assessment, the book value of goodwill by reporting unit was as follows:
Reporting Segment
 
Reporting Unit
 
Goodwill
 
 
 
 
(Millions)
Williams Partners
 
Access Midstream
 
$
452

Williams Partners
 
Northeast G&P
 
646

Williams Partners
 
West
 
47

 
 
 
 
$
1,145

For our evaluation at December 31, 2015, we continued to estimate the fair value of each reporting unit based on an income approach utilizing discount rates specific to the underlying businesses of each reporting unit. These discount rates considered variables unique to each business area, including equity yields of comparable midstream businesses, expectations for future growth and customer performance considerations. Weighted-average discount rates utilized for the reporting units were 12.8 percent for Access Midstream, 12.5 percent for Northeast G&P, and 10.4 percent for the West. As a result of the increases in discount rates during the fourth quarter, coupled with certain reductions in estimated future cash flows determined during the same period, the fair values of the Access Midstream and Northeast G&P reporting units were determined to be below their respective carrying values. For these reporting units, we calculated the implied fair value of goodwill by performing a hypothetical application of the acquisition method wherein the estimated fair value was assigned to the underlying assets and liabilities of each reporting unit. As a result of this analysis, we determined that the goodwill associated with each of these reporting units was fully impaired. For the West reporting unit, the estimated fair value significantly exceeded the carrying value and no impairment was recorded.
These results were corroborated with a market capitalization analysis whereby we reconciled the enterprise value at December 31, 2015, to the aggregate fair value of all of the reporting units and operating areas.
Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures 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 a different impairment charge in the consolidated financial statements.
During the first quarter of 2016 to-date, we have observed further significant decline in the market value of WPZ. Continuation of this condition may require evaluating our remaining goodwill for potential impairment in the future.


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Equity-method Investments
As disclosed within the Critical Accounting Estimates discussion in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Form 10-Q dated October 29, 2015, in the third quarter of 2015 in response to declining market conditions, we assessed whether the carrying amounts of certain of our equity-method investments exceeded their fair value. As a result, we recognized other-than-temporary impairment charges of $458 million and $3 million in the third-quarter related to our equity-method investments in the Delaware basin gas gathering system and certain of the Appalachia Midstream Investments, respectively. The historical carrying value of these investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with our acquisition of ACMP. We estimated the fair value of these investments using an income approach and discount rates of 11.8 percent and 8.8 percent, respectively.
In response to declining market conditions in the fourth quarter as previously discussed, we again assessed whether the carrying amounts of certain of our equity-method investments exceeded their fair value. In the fourth quarter, we recognized additional impairment charges of $45 million and $559 million related to the Delaware basin gas gathering system and certain of the Appalachia Midstream Investments, respectively, and impairment charges of $241 million and $45 million associated with UEOM and Laurel Mountain, respectively. The historical carrying value of our original 49 percent interest in UEOM was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with our acquisition of ACMP and the remaining 13 percent interest reflected our cost of acquiring that additional interest in June 2015.
We estimated the fair value of these investments using an income approach and discounts rates ranging from 10.8 percent to 14.4 percent. These discount rates considered variables unique to each business area, including equity yields of comparable midstream businesses, expectations for future growth and customer performance considerations. We estimate that an overall increase in the discount rates utilized of 50 basis points would have resulted in additional impairment charges on these investments of approximately $286 million.
Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of a different impairment charge in the consolidated financial statements.
At December 31, 2015, our Consolidated Balance Sheet includes approximately $7.3 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 an investee;
Lower than expected cash distributions from investees;
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.


59




During the first quarter of 2016 and through the date of this filing, we have observed further significant decline in the market value of WPZ. Continuation of this condition and/or further decline in such value will likely require the evaluation of certain of our equity investments for potential impairment at March 31, 2016, including those that were impaired at December 31, 2015. As a result, there is the potential for significant additional noncash impairments of our investments in the future.
Capitalized Project Development Costs
As of December 31, 2015 our Consolidated Balance Sheet includes approximately $221 million of capitalized costs associated with a limited number of developing and deferred projects, some of which are considered probable of future completion while certain others are only reasonably possible of completion. Following the significant decline in energy commodity prices and market values within our industry in 2015, we either reviewed these capitalized project costs for indicators of impairment or evaluated them for impairment as of December 31, 2015. Where performed, our impairment evaluations considered probability-weighted scenarios of undiscounted future net cash flows, including reasonably possible scenarios assuming the construction and operation of the underlying projects.
As a result of these impairment evaluations, we recognized impairment charges of $158 million associated with certain of these projects. This includes a $94 million impairment charge within our Williams Partners segment associated with development costs for a gas processing plant for which completion is now considered remote due to the unfavorable impact of low natural gas prices on customer drilling activities, and a $64 million impairment charge within our Williams NGL & Petchem Services segment associated with costs for an olefins pipeline project that is now considered remote due to the lack of customer interest.
We will continue to review and evaluate capitalized project 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. Such events or changes in circumstances may include changes in customer requirements associated with these projects, as well as overall changes in market demand. If, in a future evaluation, our carrying value for any of the projects exceeds the undiscounted future net cash flows, we will recognize an impairment for the difference between the carrying value and our estimate of fair value of the assets.
One of these projects is a Canadian PDH facility for which we have capitalized project development costs of approximately $128 million at December 31, 2015. Due to our current capital allocation considerations, management determined in the first quarter of 2016 to substantially slow the pace of development activities, limit further investment, and proceed with a strategy that could result in the potential sale of this project, entering into a partnership to fund additional development, or deferring development of the project. We have evaluated the recoverability of costs associated with this project under various scenarios of undiscounted future cash flows from the potential outcomes and determined that no impairment was required. As this strategy proceeds and our cash flow and value assumptions are updated, it is possible that some portion of these costs may be determined to be unrecoverable and thus result in an impairment.
Property, plant, and equipment and other identifiable intangible assets
We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
At December 31, 2015, our Consolidated Balance Sheet includes property, plant, and equipment and intangible assets totaling $29.6 billion and $10.0 billion, respectively. Further declines in energy commodity prices and conditions in our industry may affect our estimates of future cash flows and impact assumptions about the performance of our customers. Such indicators may cause us to evaluate these assets for potential impairment in future periods.


60




Judgments and assumptions are inherent in estimating undiscounted future cash flows, fair values, and the probability-weighting of possible outcomes. The use of alternate judgments and assumptions could result in a different determination affecting the consolidated financial statements.



61





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, 2015. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
 
Years Ended December 31,
 
2015
 
$ Change
from
2014*
 
% Change
from
2014*
 
2014
 
$ Change
from
2013*
 
% Change
from
2013*
 
2013
 
(Millions)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
Service revenues
$
5,164

 
+1,048

 
+25
 %
 
$
4,116

 
+1,177

 
+40
 %
 
$
2,939

Product sales
2,196

 
-1,325

 
-38
 %
 
3,521

 
-400

 
-10
 %
 
3,921

Total revenues
7,360

 
 
 
 
 
7,637

 
 
 
 
 
6,860

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
Product costs
1,779

 
+1,237

 
+41
 %
 
3,016

 
+11

 
 %
 
3,027

Operating and maintenance expenses
1,655

 
-163

 
-11
 %
 
1,492

 
-395

 
-36
 %
 
1,097

Depreciation and amortization expenses
1,738

 
-562

 
-48
 %
 
1,176

 
-361

 
-44
 %
 
815

Selling, general, and administrative expenses
741

 
-80

 
-12
 %
 
661

 
-149

 
-29
 %
 
512

 Impairment of goodwill
1,098

 
-1,098

 
NM

 

 

 
 %
 

Net insurance recoveries – Geismar Incident
(126
)
 
-106

 
-46
 %
 
(232
)
 
+192

 
NM

 
(40
)
Other (income) expense – net
249

 
-294

 
NM

 
(45
)
 
+119

 
NM

 
74

Total costs and expenses
7,134

 
 
 
 
 
6,068

 
 
 
 
 
5,485

Operating income (loss)
226

 
 
 
 
 
1,569

 
 
 
 
 
1,375

Equity earnings (losses)
335

 
+191

 
+133
 %
 
144

 
+10

 
+7
 %
 
134

Gain on remeasurement of equity-method investment

 
-2,544

 
-100
 %
 
2,544

 
+2,544

 
NM

 

Impairment of equity-method investments
(1,359
)
 
-1,359

 
NM

 

 

 
 %
 

Other investing income (loss) – net
27

 
-16

 
-37
 %
 
43

 
-38

 
-47
 %
 
81

Interest expense
(1,044
)
 
-297

 
-40
 %
 
(747
)
 
-237

 
-46
 %
 
(510
)
Other income (expense) – net
102

 
+71

 
NM

 
31

 
+31

 
NM

 

Income (loss) from continuing operations before income taxes
(1,713
)
 
 
 
 
 
3,584

 
 
 
 
 
1,080

Provision (benefit) for income taxes
(399
)
 
+1,648

 
NM

 
1,249

 
-848

 
NM

 
401

Income (loss) from continuing operations
(1,314
)
 
 
 
 
 
2,335

 
 
 
 
 
679

Income (loss) from discontinued operations

 
-4

 
-100
 %
 
4

 
+15

 
NM

 
(11
)
Net income (loss)
(1,314
)
 
 
 
 
 
2,339

 
 
 
 
 
668

Less: Net income (loss) attributable to noncontrolling interests
(743
)
 
+968

 
NM

 
225

 
+13

 
+5
 %
 
238

Net income (loss) attributable to The Williams Companies, Inc.
$
(571
)
 
 
 
 
 
$
2,114

 
 
 
 
 
$
430

_______
*
+ = 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.


62




2015 vs. 2014
Service revenues increased primarily due to additional revenues associated with a full year of ACMP operations in 2015, increased revenues associated with the start-up of operations at Gulfstar One during the fourth quarter of 2014, and an increase in Transco’s natural gas transportation fees due to new projects placed in service in 2014 and 2015. Revenues from operations associated with the ACMP Acquisition and the northeast region also increased due to higher volumes related to new well connects. A decrease in Canadian construction management revenues, reflecting a shift to internal customer construction projects, partially offset these increases.
Product sales decreased due to a decrease in marketing revenues primarily associated with lower prices across all products, partially offset by higher non-ethane volumes, and a decrease in revenues from our equity NGLs reflecting lower NGL prices, partially offset by higher NGL volumes. Product sales also decreased due to a decrease in olefin sales related to our Canadian operations and our RGP Splitter. The Canadian decrease was primarily due to lower prices partially offset by higher propylene volumes. The RGP Splitter decrease was primarily due to lower propane sales reflecting lower per-unit prices and lower propylene sales. These decreases are partially offset by an increase in olefin sales primarily due to resuming our Geismar operations during 2015.
Product costs decreased due to a decrease in marketing purchases primarily associated with lower per-unit costs, partially offset by higher non-ethane volumes, and a decrease in natural gas purchases associated with the production of equity NGLs primarily due to lower natural gas prices, partially offset by higher volumes. Product costs also decreased due to lower feedstock purchases in our Canadian operations primarily due to lower per-unit feedstock costs across all products as well as lower costs at our RGP Splitter driven by lower per-unit costs, partially offset by significantly higher volumes in 2015. These decreases are partially offset by an increase in olefin feedstock purchases primarily associated with resuming our Geismar operations.
Operating and maintenance expenses increased primarily due to new expenses associated with operations acquired in the ACMP Acquisition, increased growth of operating activity in certain areas, increased maintenance and repair expenses, and the return to operations of the Geismar plant. These increases are partially offset by a decrease in Canadian construction management expenses that reflect a shift to internal customer construction projects.
Depreciation and amortization expenses increased primarily due to new expenses associated with operations acquired in the ACMP Acquisition and from depreciation on new projects placed in service, including Gulfstar One and the Geismar expansion.
Selling, general, and administrative expenses (SG&A) increased primarily due to administrative expenses associated with operations acquired in the ACMP Acquisition, including $31 million higher ACMP merger and transition-related costs, partially offset by the absence of $16 million of acquisition costs incurred in 2014. In addition, 2015 includes $32 million of costs associated with our evaluation of strategic alternatives. These increases are partially offset by the absence of $18 million of project development costs incurred in 2014 related to the Bluegrass Pipeline reflecting 100 percent of such costs. The 50 percent noncontrolling interest share of these costs are presented in Net income (loss) attributable to noncontrolling interests.
Impairment of goodwill reflects a 2015 impairment charge associated with certain goodwill (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Net insurance recoveries – Geismar Incident changed unfavorably primarily due to the receipt of $126 million of insurance recoveries in 2015 as compared to the receipt of $246 million of insurance recoveries in 2014. (See Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements.)
Other (income) expense – net within Operating income (loss) changed unfavorably primarily due to increased impairments in 2015, the absence of $154 million of cash proceeds received in 2014 related to a contingency settlement gain, and the absence of a $12 million net gain recognized in 2014 related to a partial acreage dedication release. (See Note 6 – Other Income and Expenses.)
Operating income (loss) changed unfavorably primarily due to 2015 impairment of goodwill, higher impairments of certain assets, higher depreciation, operating, and maintenance expenses related to construction projects placed in


63




service and the start-up of the Geismar plant, $229 million lower NGL margins driven by lower prices, lower insurance recoveries related to the Geismar Incident, higher costs related to the merger and integration of ACMP into WPZ, and 2015 strategic alternative expenses. These decreases were partially offset by increased service revenues related to construction projects placed in service, $116 million higher olefin margins primarily due to our Geismar plant that returned to operations in 2015, and contributions from the operations acquired in the ACMP Acquisition.
Equity earnings (losses) changed favorably primarily due to the absence of equity losses from Bluegrass Pipeline and Moss Lake in 2014 and due to contributions from investments acquired in the ACMP Acquisition. In addition, equity earnings at Discovery increased $76 million primarily related to the completion of the Keathley Canyon Connector in early 2015. These changes were partially offset by $33 million of losses associated with our share of impairments recognized at equity investees in 2015. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
Gain on remeasurement of equity-method investment reflects the 2014 gain recognized as a result of remeasuring to fair value the equity-method investment that we held before we acquired a controlling interest in ACMP. (See Note 2 – Acquisitions of Notes to Consolidated Financial Statements.)
Impairment of equity-method investments reflects 2015 impairment charges associated with certain equity-method investments (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Other investing income (loss) – net changed unfavorably primarily due to lower interest income associated with a receivable related to the sale of certain former Venezuela assets.
Interest expense increased due to a $230 million increase in Interest incurred primarily due to new debt issuances in 2014 and 2015 and interest expense associated with debt assumed in conjunction with the ACMP Acquisition. This increase was partially offset by lower interest due to 2015 debt retirements and the absence of a $9 million ACMP Acquisition transaction-related financing fee incurred in the second quarter of 2014. In addition, Interest capitalized decreased $67 million primarily related to construction projects that have been placed into service. (See Note 2 – Acquisitions and Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)
Other income (expense) – net below Operating income (loss) changed favorably primarily due to a $43 million benefit related to an increase in allowance for equity funds used during construction (AFUDC) associated with an increase in spending on various Transco expansion projects and Constitution, a $14 million gain on early debt retirement in April 2015, and a $9 million contingency gain settlement.
Provision (benefit) for income taxes changed favorably primarily due to lower pretax income in 2015. 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.
The favorable change in Net income (loss) attributable to noncontrolling interests related to our investment in WPZ is primarily due to lower operating results at WPZ, our increased percentage of limited partner ownership of WPZ, and the impact of increased income allocated to the WPZ general partner, held by us, associated with IDRs. These changes are partially offset by an unfavorable change related to our investment in Gulfstar One associated with its start up in 2014.
2014 vs. 2013
Service revenues increased primarily due to contributions associated with the ACMP Acquisition beginning in third quarter 2014, including $167 million of minimum volume commitment fees, and due to new Canadian construction management services performed for third parties reported within the Other segment. Gathering fees increased driven by higher volumes and a net increase in gathering rates primarily in the Susquehanna Supply Hub. Natural gas transportation fee revenues increased primarily associated with expansion projects placed in service at Transco in 2013. In addition, Service revenues increased related to new processing, fractionation, and transportation fees from Ohio Valley Midstream facilities that were placed in service in 2013 and 2014.


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Product sales decreased primarily due to lower olefin sales volumes associated with the lack of production in 2014 as a result of the Geismar Incident, partially offset by an increase in olefin sales on the RGP splitter primarily associated with higher volumes. In addition, equity NGL sales decreased primarily reflecting lower non-ethane volumes, partially offset by higher average ethane per-unit sales prices. Crude oil, natural gas, and other marketing revenues decreased primarily related to lower volumes, while NGL marketing revenues increased primarily related to higher volumes partially offset by lower NGL prices.
Product costs decreased primarily due to lower olefin feedstock purchases related to the lack of production in 2014 as a result of the Geismar Incident. In addition, natural gas purchases associated with the production of equity NGLs decreased slightly reflecting lower volumes, which were substantially offset by higher natural gas prices. These decreases were partially offset by an increase in lower-of-cost-or-market adjustments due to significant declines in NGL prices during the fourth quarter of 2014 and lower crude oil, natural gas, and olefin volumes, partially offset by higher NGL volumes.
Operating and maintenance expenses increased primarily due to costs incurred associated with new Canadian construction management services performed for third parties. In addition, increases are due to expenses associated with operations acquired in the ACMP Acquisition beginning in third quarter 2014, including $15 million of transition-related costs, expenses incurred in 2014 associated with the installation of certain safety equipment at the Geismar plant, and higher maintenance and growth in the our operations in the Northeast region of the U.S. These increases were partially offset by a net increase in system gains and reduced gathering fuel expense in the western region operations.
Depreciation and amortization expenses increased primarily associated with assets acquired in the ACMP Acquisition beginning in third quarter 2014 and due to depreciation on new projects placed in service.
SG&A increased primarily due to operations acquired in the ACMP Acquisition beginning in third quarter 2014 including $52 million of acquisition, merger, and transition-related costs recognized in 2014, as well as $18 million of project development costs incurred in 2014 related to the Bluegrass Pipeline reflecting 100 percent of such costs. The 50 percent noncontrolling interest share of these costs are presented in Net income (loss) attributable to noncontrolling interests. In addition, SG&A increased in the Northeast region of the U.S. related to significant operational growth driven by higher gathering fees associated with higher volumes from new well connections and the completion of various compression projects.
The favorable change in Net insurance recoveries – Geismar Incident is primarily due to the receipt of $246 million of insurance recoveries in 2014, compared to the receipt of $50 million of insurance recoveries in 2013.
Other (income) expense – net within Operating income (loss) includes the following increases to net income:
$154 million of cash proceeds received in 2014 related to a contingency settlement gain;
The absence of a $25 million accrued loss recognized in 2013 associated with a producer claim against us;
The absence of a $20 million write-off in 2013 for certain pipeline assets;
The absence of $12 million of expense recognized in 2013 and $3 million of expense reversal in 2014, related to the portion of the Eminence abandonment regulatory asset that will not be recovered in rates;
A $12 million net gain recognized in 2014 related to the settlement of a partial acreage dedication release.
Other (income) expense – net within Operating income (loss) includes the following decreases to net income:
$52 million of impairment charges recognized in 2014 related to certain assets;
The absence of $16 million of income from insurance recoveries in 2013 related to the abandonment of certain Eminence storage assets;
$10 million loss on the sale of certain assets in 2014;
$9 million of expenses in excess of the insurable limit associated with the Geismar Incident;


65




A $9 million increase in expenses associated with a regulatory liability for certain employee costs;
The absence of a $9 million involuntary conversion gain recognized in 2013 related to a 2012 furnace fire at our Geismar olefins plant.
Operating income (loss) changed favorably primarily due to increased service revenues at Williams Partners associated with higher gathering volumes and new assets placed in service, a $192 million increase in net insurance recoveries related to the Geismar Incident, $167 million of minimum volume commitment fee revenue at Williams Partners related to operations acquired in the ACMP Acquisition, and $154 million of cash proceeds in 2014 related to a contingency gain settlement. These increases are partially offset by $192 million lower olefin margins, $130 million lower NGL margins and $59 million lower marketing margins, as well as higher operating costs at Williams Partners and higher impairment charges recognized in 2014.
Equity earnings (losses) changed favorably primarily due to the recognition of $96 million of equity earnings in the second half of 2014 related to equity investments acquired in the ACMP Acquisition, and an increase in equity earnings from Caiman II and Laurel Mountain. These increases are partially offset by $78 million of equity losses from Bluegrass Pipeline and Moss Lake in 2014 related primarily to the underlying write-off of previously capitalized project development costs, $19 million of equity losses associated with acquisition-related compensation expenses resulting from the ACMP Acquisition, and $17 million lower equity earnings related to our equity-method investment in ACMP since we consolidate this investment as of July 1, 2014.
Gain on remeasurement of equity-method investment represents the gain we recognized as a result of remeasuring to fair value the equity-method investment that we held before we acquired a controlling interest in ACMP.
Other investing income (loss) – net changed unfavorably primarily due to $26 million lower gains resulting from ACMP’s equity issuances prior to our consolidation of that entity beginning in third quarter 2014 and lower interest income.
Interest expense increased due to a $277 million increase in Interest incurred primarily due to new debt issuances in the fourth quarter of 2013 and the first half of 2014, as well as combining ACMP’s debt in third quarter 2014, and $9 million of ACMP Acquisition-related financing costs incurred in 2014. The increase in Interest incurred is partially offset by an increase of $40 million in Interest capitalized related to construction projects in progress.
Other income (expense) – net changed favorably primarily due to the benefit from the equity AFUDC associated with ongoing capital projects within our regulated operations.
Provision (benefit) for income taxes changed unfavorably primarily due to higher pretax income in 2014. This is partially offset by the absence of $99 million deferred income tax expense recognized in 2013, and a benefit of $34 million recorded in 2014 related to the undistributed earnings of certain foreign operations that are no longer considered 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 changed favorably primarily due to the absence of a $15 million pretax charge resulting from an unfavorable ruling associated with our former Alaska refinery related to the Trans-Alaska Pipeline System Quality Bank in 2013.
The favorable change in Net income attributable to noncontrolling interests includes the following:
$95 million favorable for our investment in WPZ primarily due to the impact of increased income allocated to the WPZ general partner associated with IDRs;
$9 million favorable for our investment in Bluegrass Pipeline that includes our partner’s 50 percent share of project development costs expensed by Bluegrass Pipeline during the portion of the first quarter of 2014 that Bluegrass Pipeline was consolidated;
$71 million unfavorable for our investment in ACMP due to the consolidation of ACMP in third quarter 2014;


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$13 million unfavorable for our investment in Cardinal resulting from the consolidation of ACMP in third quarter 2014.
Year-Over-Year Operating Results - Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 19 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.
Year-Over-Year Operating Results – Segments
Williams Partners
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Service revenues
$
5,135

 
$
3,888

 
$
2,914

Product sales
2,196

 
$
3,521

 
3,921

Segment revenues
7,331

 
$
7,409

 
$
6,835

 
 
 
 
 
 
Product costs
(1,779
)
 
(3,016
)
 
(3,027
)
Other segment costs and expenses
(2,374
)
 
(1,812
)
 
(1,610
)
Net insurance recoveries – Geismar Incident
126

 
232

 
40

Proportional Modified EBITDA of equity-method investments
699

 
431

 
209

Williams Partners Modified EBITDA
$
4,003

 
$
3,244

 
$
2,447

 
 
 
 
 
 
NGL margin
$
159

 
$
388

 
$
518

Olefin margin
226

 
110

 
302

2015 vs. 2014
Modified EBITDA increased primarily due to the acquisition of ACMP during the third quarter of 2014 and increased fee revenue associated with contributions from new and expanded facilities, including Gulfstar One during the fourth quarter 2014, in addition to resuming our Geismar operations and contributions related to the completion of the Keathley Canyon Connector at Discovery. Partially offsetting these increases to Modified EBITDA is a decrease in NGL margins as a result of a significant decline in commodity prices beginning in the fourth quarter of 2014 and lower insurance recoveries related to the Geismar Incident.
The increase in Service revenues is primarily due to $810 million additional revenues associated with a full year of ACMP operations in 2015 which includes a $72 million increase in the minimum volume commitment fees, $223 million in increased revenues associated with the start-up of operations at Gulfstar One during the fourth quarter of 2014, and a $155 million increase in Transco’s natural gas transportation fees due to new projects placed in service in 2015 and 2014. Additionally, service revenues reflect higher fees associated with increased volumes and additional contributions in the Northeast. Higher revenues in the Northeast include expanded gathering operations and processing, fractionation and transportation operations, contributing $59 million and $27 million of additional fees, respectively.
The decrease in Product sales includes:
A $1,173 million decrease in marketing revenues primarily associated with lower prices across all products, partially offset by higher non-ethane volumes (more than offset in marketing purchases).


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A $324 million decrease in revenues from our equity NGLs reflecting a decrease of $365 million due to lower NGL prices, partially offset by a $41 million increase associated with higher NGL volumes.
A $41 million decrease in revenues primarily due to lower condensate prices.
A $214 million increase in olefin sales primarily due to $298 million in higher sales from our Geismar plant that returned to operation, partially offset by a $58 million decrease from our Canadian operations and a $26 million decrease from our RGP Splitter. The decrease in Canada is comprised of $68 million in lower prices, partially offset by $10 million associated with higher propylene volumes. The lower prices reflect a 53 percent per-unit decrease in propylene prices and a 39 percent per-unit decrease in alky feedstock prices. The decrease in sales at our RGP Splitter is caused by $15 million in lower propane sales reflecting 56 percent lower per-unit prices and $11 million in lower propylene sales reflecting 47 percent lower per-unit prices, partially offset by favorable volumes.
The decrease in Product costs includes:
A $1,219 million decrease in marketing purchases primarily due to a decrease in non-ethane per-unit cost (substantial offset in marketing revenues).
A $95 million decrease in the natural gas purchases associated with the production of equity NGLs reflecting a decrease of $127 million due to lower natural gas prices, partially offset by a $31 increase associated with higher volumes.
A $20 million decrease in costs primarily due to lower gas prices.
A $98 million increase in olefin feedstock purchases is comprised of $127 million in higher purchases due to increased volumes at our Geismar plant as it returned to operation, partially offset by $16 million in lower olefin feedstock purchases in our Canadian operations primarily due to lower per-unit feedstock costs across all products and $13 million in lower costs at our RGP Splitter driven by lower per-unit costs, partially offset by significantly higher volumes in 2015.  During 2014, the splitter was running at reduced volumes because a third-party storage facility was down during the first quarter and transportation was limited due to the Geismar Incident.
The increase in Other segment costs and expenses includes:
An increase for new expenses associated with operations acquired in the ACMP Acquisition.
The absence of $154 million of cash received in the fourth quarter of 2014 associated with the resolution of a contingent gain related to claims arising from the purchase of a business in a prior period (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements).
A $94 million impairment charge associated with previously capitalized project development costs for a gas processing plant.
A $16 million increase in operating expense due to the Geismar plant returning to operation in 2015.
The absence of a $12 million net gain recognized in 2014 related to a partial acreage dedication release.
The decrease in Net insurance recoveries - Geismar Incident is primarily due to the 2015 receipt of $126 million of insurance proceeds compared to $246 million received in 2014, partially offset by the absence of covered insurable expenses in excess of our retentions (deductibles) related to the Geismar Incident in 2015 compared to $14 million in 2014.
The increase in Proportional Modified EBITDA of equity-method investments is primarily due to a full year contribution of $160 million from investments acquired in the ACMP Acquisition and a $103 million increase from


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Discovery associated with higher fee revenues attributable to the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, Caiman II increased $21 million resulting from assets placed into service in 2014 and 2015, partially offset by the absence of business interruption insurance proceeds received in the prior year, and an $11 million decrease at Laurel Mountain. The decrease at Laurel Mountain was primarily due to $13 million of impairments and lower gathering fees due to lower gathering rates indexed to natural gas prices, partially offset by 24 percent higher volumes and an increase in our ownership percentage compared to the prior year.
2014 vs. 2013
Modified EBITDA increased primarily due to the acquisition of ACMP during the third quarter of 2014, increased fee revenue associated with contributions from new and expanded facilities, higher insurance recoveries related to the Geismar Incident, and a favorable settlement. Partially offsetting these increases to Modified EBITDA are lower margins as a result of a significant decline in commodity prices beginning in the fourth quarter of 2014 and higher impairment charges related to certain materials and equipment.
The increase in Service revenues is primarily due to a $781 million of increased service revenues associated with operations acquired in the ACMP Acquisition beginning in the third quarter 2014, including $167 million of MVC fees. Additionally, service revenues reflect $88 million higher fee-based revenues resulting from higher gathering volumes driven by new well connections, the completion of various compression projects, and a net increase in gathering rates associated with customer contract modifications primarily in the Susquehanna Supply Hub of the Northeast region. Fee-based revenues also increased $22 million due to contributions from our Ohio Valley Midstream business resulting from the addition of processing, fractionation and transportation facilities placed in service in 2013 and 2014. In addition, natural gas transportation revenues increased $71 million primarily from expansion projects placed into service in 2013 for Transco and $19 million in new service fees associated with the start-up of our Gulfstar One assets.
The decrease in Product sales includes:
A $251 million decrease in olefin sales primarily associated with a $295 million decrease due to lower volumes related to the lack of production in 2014 as a result of the Geismar Incident, partially offset by a $42 million increase in revenues from our RGP Splitter associated with a $32 million increase in volumes due to a third-party storage facility resuming operations during 2014, and a $10 million increase due to higher per-unit sales prices (substantially offset in Product costs).
A $132 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $161 million due to lower non-ethane volumes, partially offset by a $29 million increase associated with higher average ethane per-unit sales prices. Equity non-ethane sales volumes are 22 percent lower primarily due to a customer contract that expired in September 2013.
A $26 million decrease in marketing revenues primarily associated with lower crude oil volumes and prices, and lower non-ethane prices, partially offset by increased non-ethane volumes.
The decrease in Product costs includes:
A $59 million decrease in olefin feedstock purchases primarily associated with a $99 million decrease due to lower volumes related to the lack of production in 2014 as a result of the Geismar Incident. Offsetting this decrease is a $36 million increase from our RGP Splitter facility attributable to a $30 million increase in volumes due to a third-party storage facility resuming operations during 2014 and a $6 million increase in per-unit costs (more than offset in Product sales).
A $2 million decrease in natural gas purchases associated with the production of equity NGLs reflecting $87 million associated with lower volumes, which were substantially offset by an $85 million increase associated with higher natural gas prices.


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A $33 million increase in marketing purchases primarily due to increased NGL volumes and lower-of-cost-or-market (LCM) inventory adjustments associated with significant declines in NGL prices during the fourth quarter of 2014.
The increase in Other segment costs and expenses includes:
A $293 million increase in expenses associated with operations acquired in the ACMP Acquisition. These expenses include Operating and maintenance expenses and Selling, general and administrative expenses (SG&A).
A $24 million increase in SG&A due to higher legal and arbitration costs, consulting expenses and employee costs.
A $95 million favorable change in Other (income) expense – net primarily due to $154 million settlement arising from the resolution of a contingent gain related to claims associated with the purchase of a business in a prior period and the absence of a $25 million accrued loss recognized in 2013 associated with a producer claim against us. Partially offsetting these gains are $52 million of impairment charges recognized in 2014 related to certain materials and equipment, a $10 million loss related to the sale of certain assets and a $9 million increase in expenses associated with a regulatory liability for certain employee costs.
A $13 million benefit related to an increase in equity AFUDC due to higher spending on Constitution and various Transco expansion projects.
The increase in Net insurance recoveries - Geismar Incident is primarily due to the 2014 receipt of $246 million of insurance proceeds compared to $50 million received in 2013, partially offset by $4 million higher covered insurable expenses in excess of our retentions (deductibles) related to the Geismar Incident in 2014 compared to 2013.
The increase in Proportional Modified EBITDA of equity-method investments is primarily due to a $178 million contribution during the second half of 2014 from investments acquired in the ACMP Acquisition. Additionally, Caiman II increased $25 million resulting from assets placed into service in 2014, business interruption insurance proceeds received in 2014 and a higher ownership percentage. Laurel Mountain also increased $12 million due to the absence of certain 2013 write-offs, increased gathering volumes and increased ownership.
Williams NGL & Petchem Services
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Service revenues
$
2

 
$

 
$

 
 
 
 
 
 
Segment costs and expenses
(85
)
 
(37
)
 
(33
)
Proportional Modified EBITDA of equity-method investments

 
(78
)
 

Williams NGL & Petchem Services Modified EBITDA
$
(83
)
 
$
(115
)
 
$
(33
)
2015 vs. 2014
The favorable change in Modified EBITDA is primarily due to the absence of our share of the 2014 write-off of previously capitalized project development costs at Bluegrass Pipeline and Moss Lake, as well as costs incurred in 2014 relating to the development of the Bluegrass Pipeline, partially offset by the 2015 write-off of previously capitalized project development costs for an olefins pipeline project.
Segment costs and expenses increased primarily due to the $64 million write-off of previously capitalized project development costs for an olefins pipeline project in 2015, partially offset by the absence of $18 million of project development costs incurred in 2014 relating to the Bluegrass Pipeline.


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The favorable change in Proportional Modified EBITDA of equity-method investments is primarily due to the absence of our share of the 2014 write-off of previously capitalized project development costs at Bluegrass Pipeline and Moss Lake.
2014 vs. 2013
The unfavorable change in Modified EBITDA is primarily due to our share of the 2014 write-off of previously capitalized project development costs at Bluegrass Pipeline and Moss Lake, as well as costs incurred in 2014 relating to the development of the Bluegrass Pipeline, partially offset by the absence of a 2013 write-off of an abandoned project.
Segment costs and expenses increased primarily due to higher expensed costs related to development projects. We expensed $18 million of project development costs during 2014 related to Bluegrass Pipeline. These higher expenses were substantially offset by the absence of a $20 million write-off of an abandoned project during 2013.
The unfavorable change in Proportional Modified EBITDA of equity-method investments is due to losses from Bluegrass Pipeline and Moss Lake related primarily to the underlying write-off of previously capitalized project development costs in 2014.
Other
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Other Modifed EBITDA
$
(29
)
 
$
103

 
$
197

2015 vs. 2014
Modified EBITDA decreased significantly as the results from the businesses acquired in the ACMP Acquisition are presented within Williams Partners for periods subsequent to the July 1, 2014, acquisition. Other included the proportional Modified EBITDA of $104 million of our former equity-method investment in ACMP for the first half of 2014, which was partially offset by $19 million associated with our share of compensation costs triggered by the ACMP Acquisition recognized in July 2014. Modified EBITDA also decreased by $30 million related to costs incurred in 2015 related to evaluating our strategic alternatives and the Merger Agreement with Energy Transfer, as well as $24 million of higher costs associated with integration and re-alignment of resources following the ACMP Acquisition and Merger. These decreases are partially offset by a $9 million contingency gain settlement recognized in fourth quarter 2015.
2014 vs. 2013
Modified EBITDA decreased significantly as the results from our former equity-method investment in ACMP are included in Other for the first half of 2014, while 2013 included a full year of results. Modified EBITDA also decreased related to $19 million of our share of compensation costs triggered by the ACMP Acquisition incurred in 2014, as previously discussed, and integration and re-alignment of resources following the ACMP Acquisition. These decreases are partially offset by lower expenses incurred related to benefits and higher benefit from the allowance for equity funds used for construction associated with capital projects within our regulated operations.


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Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
In 2015, 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 WPZ’s interstate natural gas pipeline system through projects such as Leidy Southeast and Virginia Southside to meet the demand of growth markets;
WPZ’s acquisitions of a gathering system in the Eagle Ford shale and an additional 13 percent interest in its equity-method investment in UEOM;
WPZ’s commissioning of the Bucking Horse gas processing facility joint venture in the Powder River basin Niobrara Shale;
Total per-share dividends grew 25 percent to $2.45 in 2015 compared to $1.9575 in 2014.
This growth was funded through cash flow from operations, distributions from WPZ, and additional net borrowings at WPZ.
Outlook
We continue to 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: