Attached files

file filename
EX-24 - EX-24 - WILLIAMS PARTNERS L.P.wpz_20151231xex24.htm
EX-23.2 - EX-23.2 - WILLIAMS PARTNERS L.P.wpz_20151231xex232.htm
EX-23.1 - EX-23.1 - WILLIAMS PARTNERS L.P.wpz_20151231xex231.htm
EX-31.2 - EX-31.2 - WILLIAMS PARTNERS L.P.wpz_20151231xex312.htm
EX-10.22 - EX-10.22 - WILLIAMS PARTNERS L.P.wpz_20151231xex1022.htm
EX-32 - EX-32 - WILLIAMS PARTNERS L.P.wpz_20151231xex32.htm
EX-12 - EX-12 - WILLIAMS PARTNERS L.P.wpz_20151231xex12.htm
EX-21 - EX-21 - WILLIAMS PARTNERS L.P.wpz_20151231xex21.htm
EX-31.1 - EX-31.1 - WILLIAMS PARTNERS L.P.wpz_20151231xex311.htm

\
 
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 1-34831
WILLIAMS PARTNERS L.P.

(Exact Name of Registrant as Specified in Its Charter)
Delaware
20-2485124
(State or Other Jurisdiction of Incorporation or Organization)
(I.R.S. Employer Identification No.)
 
 
One Williams Center, Tulsa, Oklahoma
74172-0172
(Address of Principal Executive Offices)
(Zip Code)

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 Units
New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
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 Exchange Act). Yes ¨ No þ

The aggregate market value of the registrant’s common units held by non-affiliates based on the closing sale price of such units as reported on the New York Stock Exchange, as of the last business day of the registrant’s most recently completed second quarter was approximately $28,408,143,353.

The registrant had 588,565,174 common units and 15,343,001 Class B units outstanding as of February 22, 2016.

DOCUMENTS INCORPORATED BY REFERENCE
None
 



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


1



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

Measurements:
Barrel: One barrel of petroleum products that equals 42 U.S. gallons
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
Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and, as of December 31, 2015, which we account for as an equity-method investment, including principally the following:
Aux Sable: Aux Sable Liquid Products LP
Caiman II: Caiman Energy II, LLC
Discovery: Discovery Producer Services LLC
Gulfstream: Gulfstream Natural Gas System, L.L.C.
Laurel Mountain: Laurel Mountain Midstream, LLC
OPPL: Overland Pass Pipeline Company LLC
UEOM: Utica East Ohio Midstream LLC
Government and Regulatory:
EPA: Environmental Protection Agency
Exchange Act: The Securities and Exchange Act of 1934, as amended
 

2



FERC: Federal Energy Regulatory Commission
IRS: Internal Revenue Service
SEC: Securities and Exchange Commission
Other:
Williams: The Williams Companies, Inc. and, unless the context otherwise indicates, its subsidiaries (other than Williams Partners L.P. and its subsidiaries)
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
Caiman Acquisition: Our 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: Our 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
NYSE: New York Stock Exchange
RGP Splitter: Refinery grade propylene splitter
Throughput:  The volume of product transported or passing through a pipeline, plant, terminal, or other facility


3



PART I
Item 1. Business
Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or like terms refer to Williams Partners L.P. and its subsidiaries. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” include the operations of our Partially Owned Entities in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our Partially Owned Entities by name, we are referring exclusively to their businesses and operations.
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 and other documents electronically with the SEC under the Exchange Act. These reports include, among other disclosures, information on any transactions we may engage in with our general partner and its affiliates and on fees and other amounts paid or accrued to our general partner and its affiliates. 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.williamslp.com. We make available free of charge through 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 Business Conduct and Ethics and the charter of the Audit Committee of our general partner’s Board of Directors are also available on our Internet website under the “Corporate Responsibility” tab. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our general partner’s Corporate Secretary at Williams Partners L.P., One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.

GENERAL
We are a publicly traded Delaware limited partnership with operations across the natural gas value chain from gathering, processing and interstate transportation of natural gas and natural gas liquids to petchem production of ethylene, propylene and other 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,Williams owns an approximate 58 percent limited partnership interest in us and all of our 2 percent general partner interest.
Williams is an energy infrastructure company that trades on the NYSE under the symbol “WMB.”
Our principal executive offices are located at One Williams Center, Tulsa, Oklahoma 74172. Our telephone number is 918-573-2000.

PUBLIC UNIT EXCHANGE
On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby Williams would have acquired all of our publicly held outstanding common units in exchange for shares of Williams’ common stock (Public Unit Exchange).
On September 28, 2015, we entered into a Termination Agreement and Release (Termination Agreement), terminating the Public Unit Exchange. Williams is required to pay us a $428 million termination fee, which will settle through a reduction of quarterly incentive distributions payable to Williams (such reduction not to exceed $209 million per quarter). Our November 2015 and February 2016 distributions to Williams were each reduced by $209 million related to this termination fee.


4



WILLIAMS MERGER AGREEMENT WITH ENERGY TRANSFER
On September 28, 2015, Williams publicly announced in a press release that it had entered into a Merger Agreement with Energy Transfer and certain of its affiliates. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies for additional information). The Merger Agreement provides that, subject to the satisfaction of customary closing conditions, Williams 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. Immediately following the completion of the ETC Merger, 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 Williams stockholders in the ETC Merger. We expect to retain our current name and remain a publicly traded limited partnership following the ETC Merger.

ACMP MERGER
Pursuant to an Agreement and Plan of Merger dated as of October 24, 2014, the general partners of Williams Partners L.P. and Access Midstream Partners, L.P. agreed to combine those businesses and their general partners, with Williams Partners L.P. merging with and into Access Midstream Partners, L.P. and the Access Midstream Partners, L.P. general partner being the surviving general partner (ACMP Merger). Following the completion of the ACMP Merger on February 2, 2015, as further described below, the surviving Access Midstream Partners, L.P. changed its name to Williams Partners L.P., and the name of its general partner was changed to WPZ GP LLC. For the purpose of the discussion in this filing, Williams Partners L.P. (WPZ) refers to the renamed merged partnership, while Pre-merger Access Midstream Partners, L.P. (ACMP) and Pre-merger Williams Partners L.P. (Pre-merger WPZ) refer to the separate partnerships prior to the consummation of the ACMP Merger and subsequent name change.

In accordance with the terms of the ACMP Merger, each ACMP unitholder received 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 common units of ACMP. Each Pre-merger WPZ common unit held by Williams was exchanged for 0.80036 common units of ACMP. Prior to the closing of the ACMP Merger, the Class D limited partner units of Pre-merger WPZ, all of which were held by Williams, were converted into Pre-merger WPZ common units on a one-for-one basis pursuant to the terms of the partnership agreement of Pre-merger WPZ. All of the general partner interests of Pre-merger WPZ were converted into general partner interests of ACMP such that the general partner interest of ACMP represents 2 percent of the outstanding partnership interest.
We completed the ACMP Merger on February 2, 2015. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies). As the ACMP Merger was between entities under common control, ACMP’s historical financial position, results of operations, and cash flows were combined with those of Pre-merger WPZ for periods during which ACMP was under common control of Williams (periods subsequent to July 1, 2014). Both Pre-merger WPZ and ACMP are reflected at Williams’ historical basis in both partnerships.

FINANCIAL INFORMATION ABOUT SEGMENTS
See Part II, Item 8 — Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — Note 18 — Segment Disclosures.

BUSINESS SEGMENTS
    
Operations of our businesses are located in North America. We manage our business and analyze our results of operations on a segment basis.

Effective January 1, 2016, businesses located in the Marcellus and Utica shale plays in the Access Midstream segment are managed within the Northeast G&P segment. The remaining Access Midstream businesses now comprise

5



the new Central segment. As a result, beginning with the reporting of first quarter 2016, our operations will be comprised of the following reportable segments:  
Central — this segment provides 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 Mid-Continent region.
Northeast G&P — this segment includes our natural gas gathering and processing and NGL fractionation businesses in the Marcellus shale region primarily in Pennsylvania, New York, and West Virginia and 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 — this segment includes our 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 — this segment includes our natural gas gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming and our interstate natural gas pipeline, Northwest Pipeline.
NGL & Petchem Services — this segment includes 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.
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.

Central
Our Central segment provides gathering, treating, and compression services to producers under long-term, fee-based contracts in Louisiana, Texas, Arkansas, and Oklahoma. These operations gathered natural gas volumes of 1,020 Tbtu and 490 Tbtu for 2015 and 2014, respectively.

6



The following tables summarize the significant consolidated assets of this segment:
 
 
Natural Gas Gathering Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Inlet
 
 
 
 
 
 
Pipeline
 
Capacity
 
Ownership
 
 
Location
 
Miles
 
(Bcf/d)
 
Interest
 
 
 
 
 
 
 
 
 
Barnett Shale
 
Texas
 
860
 
0.9
 
100%
Eagle Ford Shale
 
Texas
 
1,118
 
0.7
 
100%
Haynesville Shale
 
Louisiana
 
592
 
1.7
 
100%
Permian
 
Texas
 
346
 
0.1
 
100%
Mid-Continent
 
Arkansas, Oklahoma, Texas
 
2,112
 
0.9
 
100%
Delaware Basin Gas Gathering System
We own a non-operated 50 percent equity-method investment 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.
Northeast G&P
This segment includes our natural gas gathering and processing and NGL fractionation business in the Marcellus and Utica shale regions in Pennsylvania, West Virginia, New York, and Ohio.

The following tables summarize the significant consolidated assets of this segment:
 
 
 
 
Natural Gas Gathering Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Inlet
 
 
 
 
 
 
 
 
 
 
Pipeline
 
Capacity
 
Ownership
 
 
 
 
 
 
Location
 
Miles
 
(Bcf/d)
 
Interest
 
Supply Basins
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
_____________
(1)
Statistics reflect 100 percent of the assets from our 66 percent ownership of Cardinal gathering system.

 
 
 
 
Natural Gas Processing Facilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NGL
 
 
 
 
 
 
 
 
 
 
Inlet
 
Production
 
 
 
 
 
 
 
 
 
 
Capacity
 
Capacity
 
Ownership
 
 
 
 
 
 
Location
 
(Bcf/d)
 
(Mbbls/d)
 
Interest
 
Supply Basins
 
 
 
 
 
 
 
 
 
 
 
 
 
Fort Beeler
 
Marshall County, WV
 
0.5
 
62
 
100%
 
Appalachian
 
Oak Grove
 
Marshall County, WV
 
0.2
 
25
 
100%
 
Appalachian
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.

7



Certain Equity-Method Investments
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.

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.

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
 
 
2015
 
2014
 
2013
 
 
 
 
 
 
 
Volumes: (1)
 
 
 
 
 
 
Gathering (Tbtu)
 
1,247

 
945

 
606
Plant inlet natural gas volumes (Tbtu)
 
150

 
118

 
105
NGL production volumes (Mbbls/d) (2)
 
23

 
12

 
9
__________
(1)
Excludes volumes associated with equity-method investments.
(2)
Annual average Mbbls/d.

Atlantic-Gulf
This segment includes the Transco interstate natural gas pipeline that extends from the Gulf of Mexico to the eastern seaboard, as well as natural gas gathering, processing and treating, production handling, and NGL fractionation assets within the onshore, offshore shelf, and deepwater areas in and around the Gulf Coast states of Texas, Louisiana, Mississippi, and Alabama.

8




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.

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 to locations on its Mobile Bay Lateral. Using its Leidy Line along with market-area storage and transportation capacity, Transco can deliver an additional 5.1 MMdth 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 has natural gas storage capacity in four underground storage fields located on or near its pipeline system or market areas and operates two of these storage fields. Transco also has storage capacity in an LNG storage facility that we own and operate. The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 200 Bcf of natural gas. At December 31, 2015, our customers had stored in our 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.

Gas Gathering, Processing, and Treating Assets

The following tables summarize the significant consolidated assets of this segment:
 
 
Natural Gas Gathering Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Inlet
 
 
 
 
 
 
 
 
Pipeline
 
Capacity
 
Ownership
 
 
 
 
Location
 
Miles
 
(Bcf/d)
 
Interest
 
Supply Basins
 
 
 
 
 
 
 
 
 
 
 
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

 
 
Natural Gas Processing Facilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NGL
 
 
 
 
 
 
 
 
Inlet
 
Production
 
 
 
 
 
 
 
 
Capacity
 
Capacity
 
Ownership
 
 
 
 
Location
 
(Bcf/d)
 
(Mbbls/d)
 
Interest
 
Supply Basins
 
 
 
 
 
 
 
 
 
 
 
Markham
 
Markham, TX
 
0.5 
 
45 
 
100%
 
Western Gulf of Mexico
Mobile Bay
 
Coden, AL
 
0.7 
 
30 
 
100%
 
Eastern Gulf of Mexico


9



In addition, we own and operate several natural gas treating facilities in Texas and Louisiana which bring natural gas to specifications allowable by major interstate pipelines.

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 offshore floating production platforms provide centralized services to deepwater producers such as compression, separation, production handling, water removal, and pipeline landings.
The following tables summarize the significant crude oil transportation pipelines and production handling platforms of this segment:
 
 
 
 
 
Crude Oil Pipelines
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pipeline
 
Capacity
 
Ownership
 
 
 
 
 
 
 
Miles
 
(Mbbls/d)
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude/NGL
 
 
 
 
 
 
 
 
 
Gas Inlet
 
Handling
 
 
 
 
 
 
 
 
 
Capacity
 
Capacity
 
Ownership
 
 
 
 
 
 
 
(MMcf/d)
 
(Mbbls/d)
 
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.
Certain Equity-Method Investments
Discovery

We own a 60 percent interest in and operate the facilities of Discovery. Discovery’s assets include a 600 Mcf/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.
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. We own, through a subsidiary, a 50 percent interest in Gulfstream. We share operating responsibilities for Gulfstream with the other 50 percent owner.


10



Operating Statistics
 
2015
 
2014
 
2013
 
 
 
 
 
 
Volumes: (1)
 
 
 
 
 
Interstate natural gas pipeline throughput (Tbtu)
3,373

 
3,455

 
3,153

Gathering (Tbtu)
143

 
116

 
137

Plant inlet natural gas (Tbtu)
279

 
278

 
270

NGL production (Mbbls/d) (2)
33

 
37

 
34

NGL equity sales (Mbbls/d) (2)
6

 
5

 
7

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

 
105

 
117

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

West
This segment includes the Northwest Pipeline interstate natural gas pipeline, as well as natural gas gathering, processing, and treating assets in Colorado, New Mexico, and Wyoming.

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.

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 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.


11



Gas Gathering, Processing, and Treating Assets

The following tables summarize the significant consolidated assets of this segment:
 
 
 
Natural Gas Gathering Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Inlet
 
 
 
 
 
 
 
 
 
Pipeline
 
Capacity
 
Ownership
 
 
 
 
 
Location
 
Miles
 
(Bcf/d)
 
Interest
 
Supply Basins
 
 
 
 
 
 
 
 
 
 
 
 
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
 
(1)
 
Piceance
Niobrara
 
Wyoming
 
184
 
0.2
 
(2)
 
Powder River
__________
(1)
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.
(2)
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.
 
 
 
Natural Gas Processing Facilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NGL
 
 
 
 
 
 
 
 
 
Inlet
 
Production
 
 
 
 
 
 
 
 
 
Capacity
 
Capacity
 
Ownership
 
 
 
 
 
Location
 
(Bcf/d)
 
(Mbbls/d)
 
Interest
 
Supply Basins
 
 
 
 
 
 
 
 
 
 
 
 
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 natural gas treating facilities in New Mexico and Colorado, which bring natural gas to specifications allowable by major interstate pipelines.
Operating Statistics
 
 
2015
 
2014
 
2013
 
 
 
 
 
 
 
Volumes:
 
 
 
 
 
 
Interstate natural gas pipeline throughput (Tbtu)
 
763

 
687

 
717

Gathering (Tbtu)
 
925

 
946

 
988

Plant inlet natural gas (Tbtu)
 
1,023

 
1,022

 
1,174

NGL production (Mbbls/d) (1)
 
74

 
79

 
100

NGL equity sales (Mbbls/d) (1)
 
21

 
22

 
33

__________
(1)
Annual average Mbbls/d.


12



NGL & Petchem Services
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.

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 production 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.

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

13



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.

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.

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

Operating Statistics
 
2015
 
2014
 
2013
 
 
 
 
 
 
Volumes:
 
 
 
 
 
Geismar ethylene sales (millions of pounds)
1,066

 

 
467

Canadian propylene sales (millions of pounds)
161

 
143

 
118

Canadian NGL sales (millions of gallons)
284

 
218

 
123



14



Service Assets, Customers, and Contracts
Interstate Natural Gas Pipeline Assets
Our interstate natural gas pipelines are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce are subject to regulation. The rates are established through the FERC’s ratemaking process.

Our interstate natural gas pipelines transport and store 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. We have firm transportation and storage contracts that are generally long-term contracts with various expiration dates and account for the major portion of our regulated businesses. Additionally, we offer storage services and interruptible firm transportation services under short-term agreements.

Gathering, Processing and Treating Assets
Our 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. Our treating facilities remove water vapor, carbon dioxide and other contaminants and collect condensate, but do not extract NGLs. We are 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 revenue 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 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

15



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 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. Our gas gathering and processing customers are generally natural gas producers who have proved and/or producing natural gas fields in the areas surrounding our infrastructure. During 2015, our facilities gathered and processed gas for approximately 230 customers. Our top six gathering and processing customers accounted for approximately 74 percent of our gathering and processing fee revenues 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.

Key variables for our business will continue to be:
Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;
Prices impacting our 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 our core service areas and new step-out areas.
Crude Oil Transportation and Production Handling Assets
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. 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.

16



Significant Service Revenues
Revenues by service that exceeded 10 percent of consolidated revenue include:
 
Access Midstream
 
Northeast
G&P
 
Atlantic-
Gulf
 
West
 
Total
 
(Millions)
2015
Service:
 
 
 
 
 
 
 
 
 
Regulated natural gas transportation and storage
$

 
$

 
$
1,465

 
$
473

 
$
1,938

Gathering, processing, and production handling
1,461

 
463

 
319

 
561

 
2,804

 
 
 
 
 
 
 
 
 
 
2014
Service:
 
 
 
 
 
 
 
 
 
Regulated natural gas transportation and storage
$

 
$

 
$
1,311

 
$
470

 
$
1,781

Gathering, processing, and production handling
765

 
394

 
119

 
560

 
1,838

 
 
 
 
 
 
 
 
 
 
2013
Service:
 
 
 
 
 
 
 
 
 
Regulated natural gas transportation and storage
$

 
$

 
$
1,235

 
$
469

 
$
1,704

Gathering, processing, and production handling

 
302

 
102

 
562

 
966

We have one customer, Chesapeake Energy Corporation, and its affiliates, that accounts for 18 percent of our total revenue. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for additional information.)
REGULATORY MATTERS
Gas Pipeline and Midstream Gathering
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 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.

17



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, we own a 50 percent equity-method investment in, and operate 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.
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

18



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 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 regulates 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.

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


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

19



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 competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, fines and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses.
For additional information regarding the potential impact of federal, state, tribal or local regulatory measures on our business and specific environmental issues, please refer to “Risk Factors – Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities and expenditures and could exceed expectations” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental” and “Environmental Matters” in Note 17 – Contingent Liabilities and Commitments of our Notes to Consolidated Financial Statements.

COMPETITION
Interstate Natural Gas Pipelines
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.

20



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

EMPLOYEES
We do not have any employees. We are managed and operated by the directors and officers of our general partner. At February 1, 2016, our general partner or its affiliates employed approximately 6,578 full-time employees, a substantial portion of which support our operations and provide services to us. Additionally, our general partner and its affiliates provide general and administrative services to us. For further information, please read “Directors, Executive Officers and Corporate Governance” and “Certain Relationships and Related Transactions, and Director Independence — Reimbursement of Expenses of our General Partner.”


21



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


22



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 Williams Partners L.P. (WPZ) 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;
Events which may occur subsequent to the proposed ETC Merger including events which directly impact our business;
Expected levels of cash distributions with respect to general partner interests, incentive distribution rights and limited partner interests;
Our and our affiliate’s future credit ratings;
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;
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:
The timing and likelihood of completion of the proposed ETC Merger, including the satisfaction of conditions to the completion of the proposed ETC Merger;

23



Energy Transfer’s plans for us, as well as the other master limited partnerships it currently controls, following the completion of the proposed ETC Merger;
Disruption from the proposed ETC Merger making it more difficult to maintain business and operational relationships;
Whether we have sufficient cash from operations to enable us to pay current and expected levels of cash distributions, if any, following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner;
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;
Our allocated costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;
Changes in maintenance and construction costs;
Changes in the current geopolitical situation;
Our exposure to the credit risk of our customers and counterparties;
Risks related to financing, including restrictions stemming from 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 Securities and Exchange Commission (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

24



disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.
Limited partner units are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the risk factors discussed below in addition to the other information in this report. If any of the following risks were actually to occur, our business, results of operations and financial condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and unitholders could lose all or part of their investment.
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. If any of the risks discussed below occur, our business, prospects, financial condition, results of operations, cash flows and, in some cases our reputation, could be materially adversely affected. The occurrence of any of such risks could also materially adversely affect the value of an investment in our securities.
Throughout these risk factors reference is made to Williams and the potential impact Williams may have on our business, financial condition and operating results. As noted herein, Williams has entered into the Energy Transfer Merger Agreement with Energy Transfer and certain of its affiliates. Should the ETC Merger and the ETC Exchange each be consummated, references throughout these risk factors to Williams would instead refer to Energy Transfer or ETC, as applicable.
The pendency of the proposed ETC Merger between Energy Transfer and Williams could adversely affect our business and operations.
The proposed ETC Merger between Energy Transfer and Williams may create a significant distraction for the management team and board of directors of Williams and require Williams to expend significant time and resources. As several members of Williams’ management team also serve on our general partner’s management team we may encounter the same management distraction and constraints. 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, current and prospective employees of Williams and its affiliates that provide services to us may experience uncertainty about their future roles following the proposed ETC Merger, which may materially adversely affect Williams’ ability to attract and retain such key personnel during the pendency of the proposed ETC Merger. If Energy Transfer and Williams 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 the Williams employees that provide services to us 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.
The notes we acquired from ACMP in the ACMP Merger contain provisions that would require us to make an offer to repurchase such notes should our credit be downgraded within a period of ninety days following the completion of the proposed ETC Merger.

25



The proposed ETC Merger, if followed by a decrease in the rating of our outstanding 6.125% Senior Notes due 2022, 4.875% Senior Notes due 2023 and 4.875% Senior Notes due 2024, with an aggregate principal amount of $2.9 billion (collectively, the “Applicable Notes”) by either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services within ninety days following the closing date, will result in a change of control as defined in the indentures governing the Applicable Notes (the “Applicable Notes Indentures”). The occurrence of a change of control under the Applicable Notes Indentures will trigger an obligation for us to offer to purchase all or any part of each series of Applicable Notes at a purchase price equal to 101 percent of the principal amount of each series of Applicable Notes, plus accrued and unpaid interest thereon to the date of repurchase. If we are required to repurchase some or all of these notes, we would expect our funding sources to be derived from credit facility borrowings, new debt issuances, additional asset sales, reductions of distributions and/or equity issuances, and our ability to fund the repurchase would be subject to the same risk factors associated with financing our business. There can be no assurance regarding the covenants and restrictions in any of such financing sources and such covenants and restrictions could be more restrictive than those to which we are currently subject. We may be unable to obtain financing or sell assets to fund the repurchase on satisfactory terms, or at all.
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 condition. 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 and our ability to make cash distributions to unitholders.
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.
We recently announced that we plan to monetize assets during 2016 to fund capital and investment expenditures. 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 seek 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.
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.

26



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 and our ability to make cash distributions to unitholders.
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 investment-grade credit ratings by each of the three ratings agencies (subject to negative outlook by two such agencies).
Our ability to obtain credit in the future could be affected by Williams’ credit ratings.
Substantially all of Williams’ operations are conducted through its subsidiaries. Williams’ cash flows are substantially derived from loans, dividends and distributions paid to it by its subsidiaries. Williams’ cash flows are typically utilized to service debt and pay dividends on the common stock of Williams, with the balance, if any, reinvested in its subsidiaries as loans or contributions to capital. Due to our relationship with Williams, our ability to obtain credit will be affected by Williams’ credit ratings. Williams has been assigned sub-investment-grade credit ratings at each of the three ratings agencies. If Williams 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 Williams credit rating could also result in a further downgrading of our credit rating. A downgrading of a Williams credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.

27



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;

28



Acquisitions and capital projects may require substantial new capital, including by the issuance of debt or equity, and we may not be able to access capital markets or obtain acceptable terms.
If realized, any of these risks could have an adverse impact on our results of operations, including the possible impairment of our assets, and could also have an adverse impact on our financial position, cash flows and our ability to make cash distributions to unitholders.
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 and our ability to make cash distributions to unitholders.
We may not have sufficient cash from operations to enable us to pay cash distributions or to maintain current or expected levels of cash distributions following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
We may not have sufficient cash each quarter to pay cash distributions or maintain current or expected levels of cash distributions. The actual amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
The amount of cash that our subsidiaries and the Partially Owned Entities distribute to us;
The amount of cash we generate from our operations, our working capital needs, our level of capital expenditures, and our ability to borrow;
The restrictions contained in our indentures and credit facility and our debt service requirements;
The cost of acquisitions, if any.
Unitholders should be aware that the amount of cash we have available for distribution depends primarily on our cash flow, including cash reserves and working capital or other borrowings, and not solely on profitability, which will be affected by noncash items. As a result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during periods when we record net income. A failure to pay distributions or to pay distributions at expected levels could result in a loss of investor confidence, reputational damage and a decrease in the value of our unit price.
We are required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available for distribution to unitholders than if actual maintenance capital expenditures were deducted.
Our partnership agreement requires us to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by our conflicts committee at least once a year. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus. If we underestimate the appropriate level of estimated maintenance capital expenditures, we may have less

29



cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates. Over time, if we do not set aside sufficient cash reserves or have available sufficient sources of financing or make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the anticipated level and could be required to reduce our distributions.
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 and our ability to make cash distributions to unitholders.
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 distributions, 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 distributions 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;

30



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.
Some of our businesses, including our 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, our 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 our 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 we depend were to fail to timely supply required goods and services we may not be able to replace such goods and services in a timely manner or otherwise on favorable terms or at all. If we are unable to adequately diversify or otherwise mitigate such supplier concentration risks and such risks were realized, we 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 and our ability to make cash distributions to unitholders.
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;
We cannot control the amount of capital expenditures that we are required to fund with respect to these operations;
We are dependent on third parties to fund their required share of capital expenditures;
We may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets;
We may be forced to offer rights of participation to other joint venture participants in the area of mutual interest.
In addition, our 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. Our joint venture partners may be in a position to take actions contrary to our 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 our joint venture arrangements, we could be deemed to be in default under the joint venture agreement. Our 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 our 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 our joint ventures, or to resolve disagreements with our 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.

31



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:
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. Williams currently maintains 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 Williams, its subsidiaries, and certain of its affiliates, including us, 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, Williams is a member of Oil Insurance Limited (“OIL”), and we are an insured of OIL, an energy industry mutual insurance company, which provides coverage for damage to our property. As an insured of OIL, we are allocated a portion of shared losses and premiums in proportion to our assets.

32



As an insured member of OIL, Williams shares in the losses among other OIL members even if its property is not damaged, and as a result, we may share in any such losses incurred by Williams.
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 and make cash distributions to unitholders.
Our assets and operations, as well as our customers’ assets and operations, can be adversely affected by weather and other natural phenomena.
Our assets and operations, especially those located offshore and our customers’ assets and operations, can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes, fires and other natural phenomena and weather conditions, including extreme or unseasonable temperatures, making it more difficult for us to realize the historic rates of return associated with our assets and operations. A significant disruption in our or our customers’ operations or a significant liability for which we are not fully insured could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Acts of terrorism could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Given the volatile nature of the commodities we transport, process, store and sell, our assets and the assets of our customers and others in our industry may be targets of terrorist activities. A terrorist attack could create significant price volatility, disrupt our business, limit our access to capital markets or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport or distribute natural gas, NGLs or other commodities. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows and our ability to make cash distributions to unitholders.
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;

33



Rates, operating terms, types of services and conditions of service;
Certification and construction of new interstate pipelines and storage facilities;
Acquisition, extension, disposition or abandonment of existing interstate pipelines and storage facilities;
Accounts and records;
Depreciation and amortization policies;
Relationships with affiliated companies who are involved in marketing functions of the natural gas business;
Market manipulation in connection with interstate sales, purchases or transportation of natural gas.
Regulatory or administrative actions in these areas, including successful complaints or protests against 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

34



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

35



subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.
Our operating results for certain components of our business might fluctuate on a seasonal basis.
Revenues from certain components of our business can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and pipeline systems and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. In those instances in which we do not own the land on which our facilities are located, we obtain the rights to construct and operate our pipelines and gathering systems on land owned by third parties and governmental agencies for a specific period of time. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited term. We may not have the right of eminent domain over land owned by Native American tribes. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and cash flows and our ability to make cash distributions to unitholders.
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.
As a publicly traded partnership, these developments could significantly impair our ability to make acquisitions or finance growth projects. We distribute all of our available cash to our unitholders on a quarterly basis. We typically rely upon external financing sources, including the issuance of debt and equity securities and bank borrowings, to fund acquisitions or expansion capital expenditures. Any limitations on our access to external capital, including limitations caused by illiquidity or volatility in the capital markets, may impair our ability to complete future acquisitions and construction projects on favorable terms, if at all. As a result, we may be at a competitive disadvantage as compared to businesses that reinvest all of their available cash to expand ongoing operations, particularly under adverse economic conditions.
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 (which does not include commercial paper notes) as of December 31, 2015, was $19.18 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 and our and our material subsidiaries’ ability to enter into certain affiliate transactions and certain restrictive agreements and to change the nature of our business. Certain of our debt agreements also contain, and those we enter into in the

36



future may contain, financial covenants and other limitations with which we will need to comply. Williams’ debt agreements contain similar covenants with respect to Williams and its subsidiaries, including in some cases us.
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 partnership 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 payment of distributions, general partnership 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 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 13. 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 Williams, Williams may not be able to replace them with employees of comparable knowledge and experience. In addition, Williams 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

37



credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.
Our investments and projects located outside of the United States expose us to risks related to the laws of other countries, and the taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. These risks might delay or reduce our realization of value from our international projects.
We currently own and might acquire and/or dispose of material energy-related investments and projects outside the United States. The economic, political and legal conditions and regulatory environment in the countries in which we have interests or in which we might pursue acquisition or investment opportunities present risks that are different from or greater than those in the United States. These risks include, among others, delays in construction and interruption of business, as well as risks of renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, including with respect to the prices we realize for the commodities we produce and sell. The uncertainty of the legal environment in certain foreign countries in which we develop or acquire projects or make investments could make it more difficult to obtain nonrecourse project financing or other financing on suitable terms, could adversely affect the ability of certain customers to honor their obligations with respect to such projects or investments and could impair our ability to enforce our rights under agreements relating to such projects or investments.
Operations and investments in foreign countries also can present currency exchange rate and convertibility, inflation and repatriation risk. In certain situations under which we develop or acquire projects or make investments, economic and monetary conditions and other factors could affect our ability to convert to U.S. dollars our earnings denominated in foreign currencies. In addition, risk from fluctuations in currency exchange rates can arise when our foreign subsidiaries expend or borrow funds in one type of currency, but receive revenue in another. In such cases, an adverse change in exchange rates can reduce our ability to meet expenses, including debt service obligations. We may or may 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.
We rely on Williams for certain services necessary for us to be able to conduct our business. Certain of Williams’ accounting and information technology functions that we rely on 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 Williams and others as service providers and on Williams’ outsourcing relationships, and our limited ability to control certain costs, could have a material adverse effect on our business, results of operations and financial condition.
The execution of the integration strategy following our 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 ability to maintain relationships with service providers, customers and employees or to achieve the anticipated benefits of the ACMP Merger.

38



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 allocation from Williams for costs for its defined benefit pension plans and other postretirement benefit plans are affected by factors beyond our and Williams’ control.
As we have no employees, employees of Williams and its affiliates provide services to us. As a result, we are allocated a portion of Williams’ costs in defined benefit pension plans covering substantially all of Williams’ or its affiliates’ employees providing services to us, as well as a portion of the costs of other postretirement benefit plans covering certain eligible participants providing services to us. The timing and amount of our allocations under the defined benefit pension plans depend upon a number of factors that Williams controls, including changes to pension plan benefits, as well as factors outside of Williams’ control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase our allocations could have a significant adverse effect on our financial condition and results of operations.
Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions 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 unit 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 units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make cash distributions at our intended levels.
Risks Inherent in an Investment in Us
Williams, through its ownership of Access Midstream Ventures, L.L.C. (“Access Midstream Ventures”), indirectly owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner has limited duties to us and it and its affiliates, including Williams and Access Midstream Ventures, and may have conflicts of interest with us and may favor their own interests to the detriment of us and our common unitholders.
Access Midstream Ventures, which is owned and controlled by Williams, owns and controls our general partner and appoints all of the officers and directors of our general partner, some of whom are also officers and directors of Williams and Access Midstream Ventures. Although our general partner has a contractual duty when acting in its capacity as our general partner to act in a way that it believes is in our best interest, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its sole member, Access Midstream Ventures, and Williams. Conflicts of interest may arise between Williams, Access Midstream Ventures and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Williams and/or Access Midstream Ventures over our interests and the interests of our common unitholders. These conflicts include the following situations, among others:
Neither our partnership agreement nor any other agreement requires Williams or Access Midstream Ventures to pursue a business strategy that favors us. For example, Williams’ directors and officers have a fiduciary duty to make decisions in the best interests of the owners of Williams, which may be contrary to our best interests and the interests of our unitholders. Further, Williams is not a party to any agreement that prohibits it from competing against us in our gas gathering and processing operations and for gathering, processing and acquisition opportunities. It is possible that Williams could preclude us from pursuing opportunities in which Williams has a competitive interest.
Our general partner is allowed to take into account the interests of parties other than us, such as Williams or Access Midstream Ventures, in resolving conflicts of interest.

39



Our partnership agreement limits the liability of and reduces the duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
Williams owns units representing approximately 59 percent of the limited partner interest in us. If a vote of our limited partners is required in which Williams is entitled to vote, Williams will be able to vote its units in accordance with its own interests, which may be contrary to our interests or the interests of our unitholders.
The executive officers and certain directors of our general partner devote significant time to our business and/or the business of Williams, and will be compensated by Williams for the services rendered to them.
Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.
Our general partner determines the amount and timing of any capital expenditures and, based on the applicable facts and circumstances and, in some instances, with the concurrence of the conflicts committee of its board of directors, whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner with respect to its incentive distribution right.
Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.
Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions.
Our partnership agreement permits us to classify up to $120 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of its general partner interest or the incentive distribution rights.
Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
Our general partner, in certain circumstances, has limited liability regarding our contractual and other obligations and in some circumstances is required to be indemnified by us.
Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80 percent of the common units.
Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

40



Our partnership agreement limits our general partner’s duties to unitholders and restricts the remedies available to such unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that modify and reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. The limitation and definition of these duties is permitted by the Delaware law governing limited partnerships. In addition, our partnership agreement restricts the remedies available to holders of our limited partner units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:
Permits our general partner to make a number of decisions in its individual capacity as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include whether to exercise of its limited call right, how to exercise its voting rights with respect to the units it owns, whether to exercise its registration rights, its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement, whether to elect to reset target distribution levels and how to allocate business opportunities among us and its affiliates;
Provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;
Generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
Provides that our general partner, its affiliates and their respective officers and directors will not be liable for monetary damages to us or our limited partners or assignees for any acts or omissions unless there has been a final and nonappealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such conduct was criminal;
Provides that in resolving conflicts of interest, if Special Approval (as defined in our partnership agreement) is sought or if neither Special Approval nor unitholder approval is sought and the board of directors of our general partner determines that the resolution or course of action taken with respect to a conflict of interest satisfies certain standards set forth in our partnership agreement, it will be presumed that in making its decision our general partner or the conflicts committee of its board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Common unitholders are bound by the provisions in our partnership agreement, including the provisions discussed above.
Affiliates of our general partner, including Williams, are not limited in their ability to compete with us and may exclude us from opportunities with which they are involved. In addition, all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams, and these persons will owe fiduciary duties to Williams.
While our relationship with Williams and its affiliates is a significant attribute, it is also a source of potential conflicts. For example, Williams and its affiliates are in the natural gas business and are not restricted from competing with us. Williams and its affiliates may acquire, construct or dispose of natural gas industry assets in the future, some or all of which may compete with our assets, without any obligation to offer us the opportunity to purchase or construct

41



such assets. In addition, all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and certain of its affiliates and will owe fiduciary duties to those entities.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which the common units will trade.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by Williams and not by the unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Cost reimbursements due to our general partner and its affiliates will reduce cash available to pay distributions to unitholders.
We will reimburse our general partner and its affiliates, including Williams, for various general and administrative services they provide for our benefit, including costs for rendering administrative staff and support services to us, and overhead allocated to us. Our general partner determines the amount of these reimbursements in its sole discretion. Payments for these services will be substantial and will reduce the amount of cash available for distributions to unitholders. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.
Even if public unitholders are dissatisfied, they have little ability to remove our general partner without the consent of Williams.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by Williams. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Furthermore, if our public unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The vote of the holders of at least 66 2/3 percent of all outstanding limited partner units is required to remove our general partner. Williams and its affiliates own approximately 59 percent of our outstanding limited partner units and, as a result, our public unitholders cannot remove our general partner without the consent of Williams.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement effectively permits a change of control without unitholder consent. The new owner of our general partner would then be in a position to replace our general partner’s board of directors and officers with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.
We may issue additional common units without unitholder approval, which would dilute unitholder ownership interests.

42



Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank, or classes of securities which ultimately convert into common units, will have the following effects:
Our unitholders’ proportionate ownership interest in us will decrease;
The amount of cash available to pay distributions on each unit may decrease;
The ratio of taxable income to distributions may decrease;
The relative voting strength of each previously outstanding unit may be diminished;
The market price of the common units may decline.
The existence and eventual sale of common units or securities convertible into common units, whether held by Williams or which may be issued in acquisitions and eligible for future sale, may adversely affect the price of our common units.
As of December 31, 2015 Williams held 354,448,103 common units and Class B units, representing approximately 59 percent of our limited partner units outstanding. Williams may, from time to time, sell all or a portion of its common units. We may issue additional common units to unaffiliated third parties in connection with future acquisitions. Sales of substantial amounts of common units by Williams or third parties, or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and at a price that we deem appropriate.
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.
Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48 percent) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will equal the number of common units which would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner’s general partner interest in us (currently two percent) will be maintained at the percentage that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels.
Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

43



Pursuant to our partnership agreement, if at any time our general partner and its affiliates own more than 80 percent of the common units, our general partner will have the right, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. Our general partner may assign this right to any of its affiliates or to us. As a result, nonaffiliated unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Such unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered under the Exchange Act, we would no longer be subject to the reporting requirements of such Act.
Our partnership agreement restricts the voting rights of unitholders owning 20 percent or more of our common units.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner, its affiliates, their direct transferees and their indirect transferees approved by our general partner (which approval may be granted in its sole discretion) and persons who acquired such units with the prior approval of our general partner, cannot vote on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings, to acquire information about our operations and to influence the manner or direction of management.
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:
We were conducting business in a state but had not complied with that particular state’s partnership statute; or
Your rights to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are nonrecourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Tax Risks
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by states and localities. If the Internal Revenue Service (the “IRS”) were to treat us as a corporation for U.S. federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state or local tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

44



The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which currently has a top marginal rate of 35 percent, and would likely pay state and local income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available to pay distributions to unitholders would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distributions to unitholders would be reduced. Therefore, if we were treated as a corporation for U.S. federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of the common units.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.
The U.S. federal income tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, the U.S. President and members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect certain publicly traded partnerships. Further, the U.S. Treasury Department and the IRS have issued proposed regulations, interpreting the scope of the qualifying income requirement for publicly traded partnerships by providing industry-specific guidance with respect to activities that will generate qualifying income. The proposed regulations, once issued in final form, may change interpretations of the current law relating to the characterization of income as qualifying income and could modify the amount of our gross income we are able to treat as qualifying income for purposes of the qualifying income requirement.
Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
We prorate our items of income, gain, loss and deduction between transferors and transferees of the common units each month based upon the ownership of the common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of the common units each month based upon the ownership of the common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Although recently issued final Treasury Regulations allow publicly traded partnerships to use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, these regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge our proration method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

45



An IRS contest of the U.S. federal income tax positions we take may adversely impact the market for the common units, and the costs of any contest will reduce our cash available for distribution to our unitholders and our general partner.
The IRS may adopt positions that differ from the U.S. federal income tax positions we take and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for the common units and the price at which they trade. In addition, the costs of any contest with the IRS will result in a reduction in cash available to pay distributions to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.
Recently enacted legislation, applicable to partnership tax years beginning after 2017, alters the procedures for auditing large partnerships and for assessing and collecting taxes due (including penalties and interest) as a result of a partnership-level federal income tax audit. Under the new rules, unless we are eligible to, and do, elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed. If we are required to pay taxes, penalties and interest as a result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited tax year.
Unitholders will be required to pay taxes on their share of our income even if unitholders do not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, unitholders will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.
The tax gain or loss on the disposition of the common units could be different than expected.
If a unitholder sells its common units, it will recognize gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and its tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income that was allocated to a unitholder for a common unit, which decreased its tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than its tax basis in that common unit, even if the price the unitholder receives is less than the original cost. A substantial portion of the amount realized, regardless of whether such amount represents gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its common units, the unitholder may incur a U.S. federal income tax liability in excess of the amount of cash it received from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to the unitholders who are organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, may be taxable to them as “unrelated business taxable income.” Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay U.S. federal income tax on their share of our taxable income.
We treat each purchaser of common units in the same calendar month as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

46



Because we cannot match transferors and transferees of common units, we have adopted monthly purchase price allocation conventions and depreciation and amortization positions that may not conform to all aspects of applicable Treasury regulations. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge to those conventions could adversely affect the amount of U.S. federal income tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to unitholder tax returns.
Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our common units.
In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the unitholder does not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign countries that impose a personal income tax or an entity level tax. It is the unitholder’s responsibility to file all U.S. federal, state and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.
The sale or exchange of 50 percent or more of the total interest in our capital and profits within a 12-month period will result in a termination of our partnership for U.S. federal income tax purposes.
We will be considered to have terminated our partnership for U.S. federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all partners, which would result in us filing two tax returns for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than 12 months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, we would be treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to its partners for the tax years in the fiscal year during which the termination occurs.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of the common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the amount, character, and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholder’s tax returns without the benefit of additional deductions.
A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

47



Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, items of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder whose common units are loaned to a short seller to effect a short sale of common units. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.
Item 1B. Unresolved Staff Comments
None.
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 are constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across properties owned by others.
Item 3. Legal Proceedings
Environmental
Certain reportable legal proceedings involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings which are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.
In 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 17 – Contingent Liabilities and Commitments of the Notes to Consolidated Financial Statements included under Part II, Item 8. Financial Statements of this report, which information is incorporated by reference into this item.
Item 4. Mine Safety Disclosures
Not applicable.


48



PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information, Holders, and Distributions
Our common units are listed on the New York Stock Exchange under the symbol “WPZ.” On February 3, 2015, following the completion of the ACMP Merger, the ticker symbol for our common units listed on the New York Stock Exchange was changed from “ACMP” to “WPZ”. At the close of business on February 16, 2016, there were 588,565,174 common units outstanding, held by approximately 86 record holders, including common units held by an affiliate of Williams. In addition, our general partner holds all of our 2 percent general partner interest and incentive distribution rights.
We also have issued 15,343,001 Class B units and ownership interests in the general partner, for which there is no established public trading market. All of the Class B units and general partner interests are held by affiliates of our general partner. Class B units are entitled to paid-in-kind distributions.
For information regarding securities that may be issued under our Long-Term Incentive Plan (LTIP), please read the information under Item 12, which is incorporated by reference into this Item 5.
The following table sets forth, for the periods indicated, the high and low sales prices for our common units, as reported on the NYSE Composite Transactions Tape, and quarterly cash distributions paid to our unitholders.
 
High
 
Low
 
Cash Distribution
per Unit (1)
2015
 
 
 
 
 
First Quarter
$53.35
 
$44.85
 
$0.85
Second Quarter
59.44
 
46.75
 
0.85
Third Quarter
52.56
 
29.10
 
0.85
Fourth Quarter
36.67
 
20.48
 
0.85
2014
 
 
 
 
 
First Quarter
$59.19
 
$53.63
 
$0.575
Second Quarter
66.71
 
56.31
 
0.595
Third Quarter
65.90
 
57.78
 
0.615
Fourth Quarter
66.79
 
49.01
 
0.850
________
(1)
Represents cash distributions attributable to the quarter and declared and paid within 45 days after quarter end.
Distributions of Available Cash
Within 45 days after the end of each quarter we will distribute all of our available cash, as defined in our partnership agreement, to common unitholders of record on the applicable record date. Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:
Less the amount of cash reserves established by our general partner to:
Provide for the proper conduct of our business (including reserves for future capital expenditures and for our anticipated credit needs);
Comply with applicable law, any of our debt instruments or other agreements; or
Provide funds for distribution to our unitholders and to our general partner for any one or more of the next four quarters;

49



Plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are borrowings used solely for working capital purposes or to pay distributions made pursuant to a credit facility or other arrangement to the extent such borrowings are required to be reduced to a relatively small amount each year for an economically meaningful period of time.
We will make distributions of available cash from operating surplus for any quarter in the following manner: 
First, 98 percent to all common unitholders, pro rata, and 2 percent to our general partner, until each outstanding unit has received the minimum quarterly distribution for that quarter;
Thereafter, cash in excess of the minimum quarterly distributions is distributed to the common unitholders and the general partner based on the incentive percentages below.
Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:
 
Total Quarterly Distribution
 
Marginal Percentage
Interest in Distributions
 
Target Amount
 
Unitholders
 
General Partner
Minimum Quarterly Distribution
$0.3375
 
98%
 
2%
First Target Distribution
Up to $0.388125
 
98
 
2
Second Target Distribution
Above $0.388125 up to $0.421875
 
85
 
15
Third Target Distribution
Above $0.421875 up to $0.50625
 
75
 
25
Thereafter
Above $0.50625
 
50
 
50
If the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:
Any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished;
Our general partner will have the right to convert its general partner interest and, if any, its incentive distribution rights into common units or to receive cash in exchange for those interests.
The Class B units originated under ACMP and are not entitled to cash distributions. Instead, prior to conversion into common units, the Class B units receive quarterly distributions of additional paid-in-kind Class B units. Effective February 10, 2015, each Class B unit became convertible at the election of either us or the holders of such Class B unit into a common unit on a one-for-one basis.
The preceding discussion is based on the assumption that our general partner maintains its 2 percent general partner interest and that we do not issue additional classes of equity securities. On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby Williams would have acquired all of our publicly held outstanding common units in exchange for shares of Williams’ common stock (Public Unit Exchange). On September 28, 2015, we entered into a Termination Agreement, terminating the Public Unit Exchange. Williams is required to pay us a $428 million termination fee, which will settle through a reduction of quarterly incentive distributions payable to Williams (such reduction not to exceed $209 million per quarter). Our November 2015 and February 2016 distributions to Williams were each reduced by $209 million related to this termination fee.

50



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 Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and 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-unit amounts)
 
Revenues (1)
 
$
7,331

 
$
7,409

 
$
6,835

 
$
7,471

 
$
7,916

Net income (loss) (1) (5)
 
(1,358
)
 
1,284

 
1,119

 
1,291

 
1,604

Net income (loss) attributable to controlling interests (1) (5)
 
(1,449
)
 
1,188

 
1,116

 
1,291

 
1,604

Basic and diluted net income (loss) per common unit (1) (5)
 
(3.27
)
 
.99

 
1.76

 
2.30

 
4.51

Total assets at December 31 (1) (3) (4)
 
47,870

 
49,248

 
23,513

 
20,623

 
15,436

Commercial paper and long-term debt due within one year at December 31 (2)
 
675

 
802

 
225

 

 
324

Long-term debt at December 31 (1) (3) (4)
 
19,001

 
16,252

 
8,999

 
8,383

 
6,863

Total equity at December 31 (1) (3)
 
24,606

 
28,685

 
11,567

 
9,691

 
6,122

Cash distributions declared per common unit
 
3.400

 
3.642

 
3.415

 
3.140

 
2.900

____________
(1)
The increase in 2014 reflects the merger with ACMP. Because ACMP was under the common control of Williams, effective July 1, 2014, the merger was accounted for as a common control transaction, whereby ACMP’s assets and liabilities were combined with ours at Williams’ historical carrying values and the historical results of ACMP’s operations were combined with ours beginning with the date (July 1, 2014) Williams obtained control of ACMP. Net income (loss) per common unit was recast for years prior to 2014 to reflect the surviving entity’s equity structure. The 2014 increase in Long-term debt reflects $2.8 billion in issuances as well as $4.1 billion in debt assumed as the result of the merger with ACMP.

(2)
The increase in 2015, 2014, and 2013 reflects borrowings under our commercial paper program, which was initiated in 2013.

(3)
The change in 2012 reflects assets acquired, as well as debt and equity issuances related to the Caiman and Laser Acquisitions.
(4)
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 13 – Debt, Banking Arrangements, and Leases).
(5)
Net income (loss) for 2015 includes a $1.4 billion impairment of certain equity-method investments and a $1.1 billion impairment of goodwill.


51



Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an energy infrastructure master limited partnership focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas, NGLs, and olefins through our gas pipeline and midstream businesses. WPZ GP LLC, a Delaware limited liability company wholly owned by Williams, is our general partner.
Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure 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. These services include natural gas gathering, processing and treating, NGL fractionation and transportation, crude oil production handling and transportation, olefin production, marketing services for NGL, oil and natural gas, as well as storage facilities.
Our reportable segments as of December 31, 2015, are Access Midstream, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services which are comprised of the following businesses:
Access Midstream provides 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; the Marcellus Shale region primarily in Pennsylvania and West Virginia, the Utica Shale region of eastern Ohio, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian Basins. Access Midstream also includes 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, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 45 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
Northeast G&P is comprised of midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 69 percent equity-method investment in Laurel Mountain and a 58 percent equity-method investment in Caiman II.
Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation assets 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 60 percent equity-method investment in Discovery, and a 41 percent interest in Constitution (a consolidated entity), which is under development.
West is comprised of our gathering, processing and treating operations in New Mexico, Colorado, and Wyoming and our 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,

52



storage facilities and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL.
As of December 31, 2015, Williams holds an approximate 60 percent interest in us, comprised of an approximate 58 percent limited partner interest and all of our 2 percent general partner interest and IDRs.
Unless indicated otherwise, the following discussion and analysis of critical accounting estimates, results of operations, and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report.
Distributions
On February 12, 2016, we paid a quarterly distribution of $0.85 per unit to unitholders of record as of February 5, 2016.
Overview
Net income (loss) attributable to controlling interests for the year ended December 31, 2015, decreased $2.64 billion compared to the year ended December 31, 2014, primarily due to impairment charges associated with certain goodwill, equity-method investments, and other assets (See Note 16 – 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 since 2014, higher operations and maintenance expenses, as well as increased interest expense associated with new debt issuances. These decreases were partially offset by new fee-based revenues associated with the start-up of Gulfstar One in the fourth quarter of 2014 and an increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2014 and 2015. See additional discussion in Results of Operations.
Public Unit Exchange
On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby Williams would have acquired all of our publicly held outstanding common units in exchange for shares of Williams’ common stock (Public Unit Exchange).
On September 28, 2015, we entered into a Termination Agreement and Release, terminating the Public Unit Exchange. Under the terms of the Termination Agreement, Williams is required to pay us a $428 million termination fee, which will settle through a reduction of quarterly incentive distributions payable to Williams (such reduction not to exceed $209 million per quarter). Our November 2015 and February 2016 distributions to Williams were each reduced by $209 million related to this termination fee.
Williams’ Merger Agreement with Energy Transfer
On September 28, 2015, Williams publicly announced in a press release that it had 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, Williams 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. Immediately following the completion of the ETC Merger, 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 Williams stockholders in the ETC Merger. We expect to retain our current name and remain a publicly traded limited partnership following the ETC Merger.
ACMP Merger
Pursuant to an Agreement and Plan of Merger dated as of October 24, 2014, the general partners of Williams Partners L.P. and Access Midstream Partners, L.P. agreed to combine those businesses and their general partners, with Williams Partners L.P. merging with and into Access Midstream Partners, L.P. and the Access Midstream Partners, L.P.

53



general partner being the surviving general partner (ACMP Merger). Following the completion of the ACMP Merger on February 2, 2015, as further described below, the surviving Access Midstream Partners, L.P. changed its name to Williams Partners L.P., and the name of its general partner was changed to WPZ GP LLC. For the purpose of these financial statements and notes, Williams Partners L.P. (WPZ) refers to the renamed merged partnership, while Pre-merger Access Midstream Partners, L.P. (ACMP) and Pre-merger Williams Partners L.P. (Pre-merger WPZ) refer to the separate partnerships prior to the consummation of the ACMP Merger and subsequent name change.

In accordance with the terms of the ACMP Merger, each ACMP unitholder received 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 common units of ACMP. Each Pre-merger WPZ common unit held by Williams was exchanged for 0.80036 common units of Pre-merger ACMP. Prior to the closing of the ACMP Merger, the Class D limited partner units of Pre-merger WPZ, all of which were held by Williams, were converted into Pre-merger WPZ common units on a one-for-one basis pursuant to the terms of the partnership agreement of Pre-merger WPZ. All of the general partner interests of Pre-merger WPZ were converted into general partner interests of Pre-merger ACMP such that the general partner interest of ACMP represents 2 percent of the outstanding partnership interest.
We completed the ACMP Merger on February 2, 2015. (See Note 1 – General, Description of Business, and Basis of Presentation for additional information). As the ACMP Merger was between entities under common control, ACMP’s historical financial position, results of operations, and cash flows were combined with those of Pre-merger WPZ for periods during which ACMP was under common control of Williams (periods subsequent to July 1, 2014). Both Pre-merger WPZ and ACMP are reflected at Williams’ historical basis in both partnerships.
Geismar Incident
On June 13, 2013, an explosion and fire occurred at our 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.
Access Midstream
Eagle Ford gathering system
In May 2015, we 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, we acquired an approximate 13 percent equity interest in UEOM for approximately $357 million, increasing our ownership from 49 percent to approximately 62 percent.
Utica and Haynesville gas gathering agreements
In September 2015, we completed an agreement to expand 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, we 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).

54



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.
West
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.
Atlantic-Gulf
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.
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.
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.
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

55



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.
 
The potential impact of commodity price volatility on our business is further discussed in the following Company Outlook.
Company Outlook
As previously discussed, Williams entered into a Merger Agreement with Energy Transfer and certain of its affiliates and expects 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 unitholders.
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 2016 as compared to 2015. Anticipating these conditions, our business plan for 2016 includes significant reductions

56



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 $2.1 billion, which is a $1.2 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 Atlantic-Gulf 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:
Downgrade of our investment grade 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;

57



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:
Access Midstream
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.
Northeast G&P
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-Gulf
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

58



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 other necessary regulatory approvals, with an expected capacity of 650 Mdth/d.
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

59



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.
NGL & Petchem Services
Redwater Expansion
In association with Williams’ 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 to provide NGL transportation and fractionation services to Williams. With this capacity increase, additional NGL/olefins mixtures from Williams will be fractionated into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate under a long-term, fee-based agreement. This capacity increase at Redwater is expected to be placed into service during the first quarter of 2016.
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We have reviewed the selection, application, and disclosure of these critical accounting estimates with our general partner’s 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.
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 Central and Northeast Region reporting units as of September 30, 2015. The goodwill associated with these reporting units was initially recorded during the third quarter of 2014 in conjunction with Williams’ acquisition of ACMP. At September 30, 2015, the fair value of these reporting units, determined using an income approach, exceeded the carrying value and thus no impairment was recorded. However, we disclosed that the evaluation was sensitive to an increase in the discount rates utilized, which at the time was approximately 10 percent for each reporting unit evaluated.
On October 1, 2015, we performed our annual review of the goodwill associated with the Northeast G&P and West G&P 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)
Access Midstream
 
Central Region
 
$
250

Access Midstream
 
Northeast Region
 
202

Northeast G&P
 
Northeast G&P
 
646

West
 
West G&P
 
47

 
 
 
 
$
1,145



60



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 13.1 percent for the Central Region, 12.4 percent for the Northeast Region, 12.5 percent for Northeast G&P, and 11.1 percent for West G&P. 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 Central Region, Northeast Region 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 G&P reporting unit, the estimated fair value exceeded the carrying value by approximately $278 million, or 11 percent. We estimate that an overall increase in the discount rate utilized of 250 basis points would have resulted in a potential impairment of goodwill for this reporting unit.
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.
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 Williams’ 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 Williams’ 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 discount 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.

61



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.
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.
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 $28.6 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.
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.

62



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
$
5,135

 
+1,247

 
+32
 %
 
$
3,888

 
+974

 
+33
 %
 
$
2,914

Product sales
2,196

 
-1,325

 
-38
 %
 
3,521

 
-400

 
-10
 %
 
3,921

Total revenues
7,331

 
 
 
 
 
7,409

 
 
 
 
 
6,835

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
Product costs
1,779

 
+1,237

 
+41
 %
 
3,016

 
+11

 
 %
 
3,027

Operating and maintenance expenses
1,625

 
-348

 
-27
 %
 
1,277

 
-197

 
-18
 %
 
1,080

Depreciation and amortization expenses
1,702

 
-551

 
-48
 %
 
1,151

 
-360

 
-46
 %
 
791

Selling, general, and administrative expenses
684

 
-51

 
-8
 %
 
633

 
-114

 
-22
 %
 
519

Impairment of goodwill
1,098

 
-1,098

 
NM

 

 

 
 %
 

Net insurance recoveries – Geismar Incident
(126
)
 
-106

 
-46
 %
 
(232
)
 
+192

 
NM

 
(40
)
Other (income) expense – net
186

 
-231

 
NM

 
(45
)
 
+96

 
NM

 
51

Total costs and expenses
6,948

 
 
 
 
 
5,800

 
 
 
 
 
5,428

Operating income
383

 
 
 
 
 
1,609

 
 
 
 
 
1,407

Equity earnings (losses)
335

 
+107

 
+47
 %
 
228

 
+124

 
+119
 %
 
104

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

 
NM

 

 

 
 %
 

Other investing income (loss) – net
2

 

 
 %
 
2

 
+3

 
NM

 
(1
)
Interest expense
(811
)
 
-249

 
-44
 %
 
(562
)
 
-175

 
-45
 %
 
(387
)
Other income (expense) – net
93

 
+57

 
+158
 %
 
36

 
+10

 
+38
 %
 
26

Income (loss) before income taxes
(1,357
)
 
 
 
 
 
1,313

 
 
 
 
 
1,149

Provision (benefit) for income taxes
1

 
+28

 
+97
 %
 
29

 
+1

 
+3
 %
 
30

Net income (loss)
(1,358
)
 
 
 
 
 
1,284

 
 
 
 
 
1,119

Less: Net income attributable to noncontrolling interests
91

 
+5

 
+5
 %
 
96

 
-93

 
NM

 
3

Net income (loss) attributable to controlling interests
$
(1,449
)
 
 
 
 
 
$
1,188

 
 
 
 
 
$
1,116

_________
*
+ = 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.
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. Northeast G&P and Access Midstream also reflect higher volumes related to new well connects in several regions.
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

63



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 the 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, and increased maintenance and repair expenses, as well as the return to operations of the Geismar plant.
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 an increase in administrative expenses primarily associated with operations acquired in the ACMP Acquisition.
Impairment of goodwill reflects a 2015 impairment charge associated with certain goodwill (see Note 16 – 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 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).
Other (income) expense – net within Operating income changed unfavorably primarily due to the absence of $154 million of cash proceeds received in 2014 related to a contingency settlement gain, increased impairments in 2015, and the absence of a $12 million net gain recognized in 2014 related to a partial acreage dedication release.
Operating income decreased primarily due to 2015 impairment of goodwill, higher impairments of certain assets, higher depreciation, operating, and maintenance expenses related to construction projects placed in service and the start-up of the Geismar plant, $229 million lower NGL margins driven by lower prices, and lower insurance recoveries related to the Geismar Incident. 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 $75 million related to contributions of equity-method investments at Access Midstream for a full year in 2015, as well as a $76 million increase at Discovery 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 the equity investees in 2015 (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements).
Impairment of equity-method investments reflects 2015 impairment charges associated with certain equity-method investments (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Interest expense increased due to a $181 million increase in Interest incurred primarily due to new debt issuances in 2014 and 2015, as well as 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. In addition, Interest capitalized

64



decreased $68 million primarily related to construction projects that have been placed into service. (See Note 2 – Acquisitions and Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)
Other income (expense) – net below Operating income changed favorably primarily due to a $43 million benefit related to an increase in the allowance for equity funds used for construction (AFUDC) associated with an increase in spending on various Transco expansion projects and Constitution, as well as a $14 million gain on early debt retirement in April 2015.
Provision (benefit) for income taxes changed favorably primarily due to lower foreign pretax income associated with our Canadian operations. See Note 8 – 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.
Net income attributable to noncontrolling interests changed favorably primarily due to the absence of 2014 income allocated to ACMP interests held by the public that is presented within noncontrolling interests for periods prior to consummation of the ACMP Merger, partially offset by higher income allocated to noncontrolling interests associated with the start-up of Gulfstar One.
2014 vs. 2013
Service revenues increased primarily due to contributions from Access Midstream beginning in third quarter 2014, including $167 million of minimum volume commitment fees. 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.
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 expenses associated with Access Midstream 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 our Northeast G&P operations. These increases were partially offset due primarily to a net increase in system gains, and reduced gathering fuel expense in the West operations.

Depreciation and amortization expenses increased primarily due to expenses associated with Access Midstream beginning in third quarter 2014 and due to depreciation on new projects placed in service.
SG&A increased primarily due to expenses associated with Access Midstream beginning in third quarter 2014, including $42 million of acquisition, merger, and transition-related costs recognized in 2014. In addition, SG&A increased related to operational growth in our Northeast G&P operations.

65



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. (See Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements.)
Other (income) expense – net within Operating income 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 $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 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;
A $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;
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 changed favorably primarily due to increased service revenues of $193 million related to our pre-merger operations, a $192 million increase in net insurance recoveries related to the Geismar Incident, $167 million of minimum volume commitment fee revenue at Access Partners, 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 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 held by Access Midstream, and higher equity earnings from Caiman II and Laurel Mountain.

Interest expense increased due to a $206 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 expense associated with Access Midstream’s debt beginning in the third quarter of 2014, and $9 million of Access Midstream acquisition-related financing costs incurred in 2014. The increase in Interest incurred is partially offset by an increase of $31 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 favorably primarily due to the absence of Texas franchise tax incurred related to a second-quarter 2013 tax law change, partially offset by an unfavorable increase due to higher foreign pretax income associated with our Canadian operations.

66



Net income attributable to noncontrolling interests changed unfavorably due to income allocated to ACMP interests held by the public that is presented within noncontrolling interests for periods prior to consummation of the ACMP Merger.
Year-Over-Year Operating Results - Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 18 – 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
Access Midstream
 
Years Ended December 31,
 
2015
 
2014
 
(Millions)
Service revenues
$
1,523

 
$
765

 
 
 
 
Segment costs and expenses
(582
)
 
(301
)
Proportional Modified EBITDA of equity-method investments
338

 
178

Access Midstream Modified EBITDA
$
1,279

 
$
642

The results of operations for the Access Midstream segment are only presented for periods under common control (periods subsequent to July 1, 2014) and are reflected at Williams’ historical basis in the underlying operations (see Note 2 – Acquisitions).
2015 vs. 2014
Modified EBITDA increased primarily due to the consolidation of Access Midstream results for the entire year of 2015, an increase in revenues from increased volumes under the MVCs, and a decrease in acquisition, merger, and transition-related expenses.
Service revenues increased primarily due to the consolidation of Access Midstream for all of 2015 and approximately $72 million recognized associated with increased volumes under the MVCs in the Barnett and Haynesville Shale areas. Service revenues also increased by $55 million due to higher volumes related to new well connects in the Utica and Haynesville Shale areas.
Segment costs and expenses increased primarily due to the consolidation of Access Midstream for all of 2015 and higher allocated support costs in 2015, partially offset by lower acquisition, merger, and transition-related expenses.
Proportional Modified EBITDA of equity-method investments increased primarily due to the consolidation of Access Midstream beginning with the third quarter of 2014, partially offset by impairments of $20 million in 2015.
2014 vs. 2013
As previously noted, the results for the Access Midstream segment are only presented for periods subsequent to July 1, 2014. Service revenues for 2014 reflect the recognition of $167 million related to MVCs associated with gas gathering agreements in the Barnett and Haynesville Shale areas.

67



Northeast G&P
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Service revenues
$
548

 
$
451

 
$
335

Product sales
127

 
230

 
166

Segment revenues
675

 
681

 
501

 
 
 
 
 
 
Product costs
(121
)
 
(221
)
 
(160
)
Other segment costs and expenses
(302
)
 
(117
)
 
(242
)
Proportional Modified EBITDA of equity-method investments
62

 
52

 
15

Northeast G&P Modified EBITDA
$
314

 
$
395

 
$
114

2015 vs. 2014
Modified EBITDA decreased primarily due to the absence of cash received from a fourth quarter 2014 settlement discussed below, partially offset by higher service revenues driven by new well connections and the completion of various compression, processing, fractionation, and transportation projects.
Service revenues increased primarily due to $59 million higher gathering fees associated with 10 percent higher volumes driven by new well connections and the completion of various compression projects, as well as an increase in gathering rates, primarily in the Susquehanna Supply Hub. Service revenues also increased $27 million due to contributions from our Ohio Valley Midstream business resulting from the addition of processing, fractionation, and transportation facilities placed in service in 2014 and 2015. Overall volume growth was reduced as a result of producers deferring production due to low natural gas prices.
Product sales decreased primarily due to a $104 million decline in marketing sales in the Ohio Valley Midstream business, primarily due to a 66 percent decline in non-ethane per unit marketing sales prices, partially offset by a 39 percent increase in NGL volumes. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs.
Other segment costs and expenses increased primarily due to 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 7 – Other Income and Expenses of Notes to Consolidated Financial Statements) and the absence of a $12 million net gain in 2014 related to a partial acreage dedication release. Additionally, costs increased due to $40 million higher operations and maintenance expenses resulting from growth in operations and higher pipeline remediation costs, and $29 million of impairment charges related to certain assets. Partially offsetting these increases were the absence of certain 2014 expenses, including $30 million of impairment charges related to certain assets and $6 million in costs resulting from fire damage at a compressor station in the Susquehanna Supply Hub.
Proportional Modified EBITDA of equity-method investments increased primarily due to a $21 million increase from Caiman II 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 from 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 cash received from a fourth quarter 2014 settlement discussed above and an increase in service revenues, partially offset by impairment charges related to certain materials and equipment.

68



Service revenues increased primarily due to $88 million higher gathering fees associated with 30 percent higher volumes driven by new well connections and the completion of various compression projects, and a net increase in gathering rates associated with customer contract modifications, primarily in the Susquehanna Supply Hub. Service 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.
Product sales increased due primarily to growth in the NGL marketing activities attributable to the Ohio Valley Midstream business. The changes in marketing revenues are partially offset by similar changes in marketing purchases, reflected above as Product costs.
Other segment costs and expenses decreased primarily due to a $154 million contingency gain settlement discussed above, the absence of a $25 million accrued loss incurred in 2013 associated with a producer claim against us, and a $12 million net gain in 2014 related to a partial acreage dedication release. These decreases are partially offset by $30 million of impairment charges related to certain materials and equipment, $6 million of costs resulting from fire damages at a compressor station in the Susquehanna Supply Hub, and higher expenses associated with maintenance and growth in these operations.

Proportional Modified EBITDA of equity-method investments increased primarily due to a $25 million increase from Caiman II resulting primarily from business interruption insurance proceeds received in 2014 and higher volumes due to assets placed into service in 2014. In addition, Laurel Mountain increased $12 million primarily due to 20 percent higher gathering volumes, an 18 percent increased ownership percentage beginning in fourth quarter 2014, and the absence of certain write-offs in 2013.
Atlantic-Gulf

Years Ended December 31,

2015

2014
 
2013

(Millions)
Service revenues
$
1,881

 
$
1,501

 
$
1,424

Product sales
463

 
853

 
925

Segment revenues
2,344

 
2,354

 
2,349

 
 
 
 
 
 
Product costs
(434
)
 
(791
)
 
(843
)
Other segment costs and expenses
(644
)
 
(649
)
 
(637
)
Proportional Modified EBITDA of equity-method investments
257

 
151

 
144

Atlantic-Gulf Modified EBITDA
$
1,523

 
$
1,065

 
$
1,013

 
 
 
 
 
 
NGL margin
$
27

 
$
57

 
$
79

2015 vs. 2014
Modified EBITDA increased primarily due to higher service revenues related to new fees from Gulfstar One, Transco expansion projects placed into service, and higher earnings at Discovery due to the completion of the Keathley Canyon Connector in the first quarter of 2015, partially offset by $30 million lower NGL margins driven by lower prices.
Service revenues increased primarily due to $223 million of new fees associated with the start-up of operations at Gulfstar One in the fourth quarter of 2014 in addition to the related transportation fees, and a $155 million increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2014 and 2015.

69



Product sales decreased primarily due to:
A $350 million decrease in NGL and crude oil marketing revenues. NGL marketing sales decreased $185 million primarily due to a 54 percent decrease in non-ethane per-unit sales prices and a 5 percent decrease in non-ethane volumes primarily due to the absence of a 2014 temporary increase in production in the western Gulf Coast. Crude oil marketing sales decreased $165 million primarily due to 48 percent lower crude oil per barrel sales prices and lower volumes due to natural declines in production from certain deepwater wells flowing on our Mountaineer crude oil pipeline. These changes in marketing revenues are offset by similar changes in marketing purchases.
A $39 million decrease in revenues from our equity NGLs primarily due to 54 percent lower realized non-ethane per-unit sales prices.
Product costs decreased primarily due to:
A $353 million decrease in marketing purchases (offset in Product sales).
A $9 million decrease in natural gas purchases associated with the production of equity NGLs primarily due to lower natural gas prices.
Other segment costs and expenses decreased primarily due to a $43 million higher benefit related to a favorable change in equity AFUDC associated with an increase in spending on various Transco expansion projects and Constitution, as well as lower impairments of certain assets. These decreases were substantially offset by higher operating and maintenance expenses primarily due to an increase in miscellaneous contractual services primarily due to general maintenance, hydrostatic and other pipeline testing and higher employee-related and operating tax expenses, in addition to higher expenses related to Gulfstar One which was placed in service in late 2014. Additionally, expenses recognized in 2015 include the establishment of a regulatory liability associated with rate collections in excess of our pension funding obligation and increased project development costs.
Proportional Modified EBITDA of equity-method investments increased primarily related to higher fee revenues at Discovery due to the completion of the Keathley Canyon Connector in the first quarter of 2015.
2014 vs. 2013
Modified EBITDA increased primarily due to higher service revenues, partially offset by $22 million lower NGL margins reflecting lower volumes, and higher Other segment costs and expenses.
Service revenues increased primarily due to a $71 million increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service and new rates effective in 2013. Additionally, Gulfstar One fees were $19 million in 2014 due to the start-up of operations. Western Gulf Coast fees increased $8 million associated with increased production and a short-term increase in volumes. These increases are partially offset by lower production handling and crude oil transportation fee revenues in the eastern Gulf Coast primarily driven by lower Bass Lite production area volumes, natural declines of other fields, and producers’ operational issues.
Product sales decreased primarily due to:
A $61 million decrease in marketing revenues reflecting a decrease in crude oil marketing sales, partially offset by an increase in NGL marketing sales. Crude oil marketing sales decreased primarily due to lower crude oil volumes related to natural declines in production areas served by our Mountaineer crude oil pipeline. NGL marketing sales increased primarily due to higher NGL volumes associated with a short-term increase in production in the western Gulf Coast. These changes in marketing revenues are offset by similar changes in marketing purchases;

70



A $25 million decrease in revenues from our equity NGLs reflecting lower equity NGL sales volumes. Equity NGL sales volumes are 28 percent lower driven by 25 percent lower non-ethane volumes as a result of customer contract changes and producers’ operational issues;
An $8 million increase in system management gas sales from Transco. System management gas sales are offset in Product costs and, therefore, have no impact on Modified EBITDA.
Product costs decreased primarily due to:
A $60 million decrease in marketing purchases (offset in Product sales);
An $8 million increase in system management gas costs (offset in Product sales).
Other segment costs and expenses increased due to an increase in other materials and supplies cost, miscellaneous contractual services costs primarily due to various repairs and maintenance projects, and impairment charges recognized in 2014 related to certain materials and equipment. These increases are partially offset by a favorable change in equity AFUDC related to an increase in spending on Constitution and various Transco expansion projects.
West
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Service revenues
$
1,055

 
$
1,050

 
$
1,054

Product sales
257

 
546

 
772

Segment revenues
1,312

 
1,596

 
1,826

 
 
 
 
 
 
Product costs
(145
)
 
(270
)
 
(380
)
Other segment costs and expenses
(610
)
 
(503
)
 
(522
)
West Modified EBITDA
$
557

 
$
823

 
$
924

 
 
 
 
 
 
NGL margin
$
105

 
$
255

 
$
369

2015 vs. 2014
Modified EBITDA decreased due to lower NGL margins and a certain noncash impairment, partially offset by the addition of $26 million in Modified EBITDA attributed to the Niobrara operations, which were part of the ACMP Acquisition. The decrease in NGL margins are attributable to lower NGL prices and volumes, partially offset by lower per-unit natural gas costs.
Service revenues increased due to $52 million higher gathering and processing revenues from the Niobrara operations due to the consolidation of Niobrara results for the entire year of 2015 and the start-up of the Bucking Horse processing facility in 2015. This increase is partially offset by $25 million lower commodity-based processing fees, the absence of $11 million in minimum volume shortfall payments received in 2014, and $10 million associated with lower volumes due primarily to natural declines.
Product sales decreased primarily due to:
A $215 million decrease in revenues from our equity NGLs reflecting a $205 million decrease associated with 51 percent lower average per-unit sales prices driven by the significant decline in NGL prices, as well as a $10 million decrease in volumes primarily attributed to changes in inventory, plant maintenance, and natural declines.

71



A $54 million decrease in marketing revenues primarily due to a 60 percent decrease in average non-ethane per-unit sales prices driven by the significant decline in NGL prices, partially offset by 24 percent higher non-ethane volumes (offset in Product costs).
A $20 million decrease in other product sales, primarily condensate sales, driven by lower prices.
Product costs decreased primarily due to:
A $65 million decrease in natural gas purchases associated with the production of equity NGLs reflecting 41 percent lower average per-unit natural gas costs as a result of the significant decline in natural gas prices.
A $52 million decrease in marketing purchases (offset in Product sales).
An $8 million decrease in other product purchases driven by lower natural gas prices.
Other segment costs and expenses increased primarily due to a $94 million impairment charge (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk) associated with previously capitalized project development costs for a gas processing plant, the addition of $26 million from the Niobrara operations, and a $12 million net decrease in system gains. These increases were partially offset by $15 million of lower allocated support costs due to relative growth in the other segments.
2014 vs. 2013
Modified EBITDA decreased primarily due to $114 million lower NGL margins and lower Service revenues, partially offset by a net increase in system gains and reduced gathering fuel expense. The decrease in NGL margins reflects lower NGL volumes, higher per-unit natural gas costs, and slightly lower average non-ethane sales prices driven by the significant decline in energy commodity prices during the fourth quarter of 2014.
Service revenues decreased primarily due to an $18 million decrease in gathering and processing fees driven by lower volumes associated with natural declines, certain contract changes, and lower margins from commodity-based fees, partially offset by the addition of $16 million of gathering and processing revenues from the Niobrara operations as a result of the ACMP Acquisition, as well as an increase in minimum volume fees.
Product sales decreased primarily due to:
A $156 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $144 million due to lower volumes and $12 million primarily due to 2 percent lower average non-ethane per-unit sales prices driven by the significant decline in energy commodity prices during the fourth quarter of 2014. Lower volumes are driven by a 24 percent decrease in non-ethane volumes primarily due to a customer contract that expired in September 2013.
A $74 million decrease in NGL marketing revenues primarily due to lower volumes largely related to the expiration of a customer contract, as well as lower per-unit prices (offset in Product costs).
Product costs decreased primarily due to:
A $76 million decrease in NGL marketing purchases (offset in Product sales).
A $42 million decrease in natural gas purchases associated with the production of equity NGLs reflecting a $67 million decrease related to lower volumes, partially offset by a $25 million increase driven by higher per-unit natural gas costs.
The decrease in Other segment costs and expenses is primarily due to a $21 million net increase in system gains and $11 million in reduced gathering fuel expense, partially offset by the addition of $15 million from the Niobrara operations.

72



NGL & Petchem Services 
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Service revenues
$
139

 
$
126

 
$
112

Product sales
1,921

 
2,986

 
3,155

Segment revenues
2,060

 
3,112

 
3,267

 
 
 
 
 
 
Product costs
(1,656
)
 
(2,829
)
 
(2,753
)
Other segment costs and expenses
(251
)
 
(241
)
 
(209
)
Net insurance recoveries - Geismar Incident
126

 
232

 
40

Proportional Modified EBITDA of equity-method investments
42

 
50

 
50

NGL & Petchem Services Modified EBITDA
$
321

 
$
324

 
$
395

 
 
 
 
 
 
Olefins margin
$
226

 
$
110

 
$
302

NGL margin
21

 
68

 
64

2015 vs. 2014
Modified EBITDA is lower in 2015 compared to 2014 primarily due to lower insurance proceeds related to the Geismar Incident and lower NGL margins reflecting lower commodity prices partially offset by higher volumes. Partially offsetting these decreases are higher olefin margins driven by the return to operation of the Geismar plant and higher marketing margins.
Service revenues increased primarily due to increased third-party volumes stored at our Conway facility, as well as increased rates in 2015.
Product sales decreased primarily due to:
A $1,187 million decrease in marketing revenues primarily due to lower prices across all products, especially non-ethane, partially offset by higher non-ethane volumes (more than offset in Product costs).
A $73 million decrease in Canadian NGL sales revenues comprised of a $120 million decrease associated with lower prices, partially offset by an increase of $47 million associated with higher volumes. Prices reflect 82 percent, 33 percent, and 46 percent per-unit lower propane, ethane, and butane prices, respectively. The higher volumes are driven by higher propane and ethane volumes, primarily due to the absence of certain operational issues at our off-gas provider and our Redwater facility in 2014. Propane volumes also increased due to sales from inventory in anticipation of a planned shutdown of the Redwater fractionator to finish construction of the expansion, as well as higher quantities of propane being sold into the U.S. for storage due to the unfavorable propane market in Canada.
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.

73



Product costs decreased primarily due to:
A $1,228 million decrease in marketing product costs primarily due to lower non-ethane per-unit costs, partially offset by higher non-ethane volumes (substantially offset by lower Product sales).
A $26 million decrease in NGL product costs reflecting a $49 million decline in the price of natural gas associated with the production of equity NGLs, partially offset by a $23 million increase primarily associated with higher propane and ethane volumes.
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 unfavorable change in Other segment costs and expenses is primarily due to higher operating expenses including increased expenses associated with the return to operation of the Geismar plant.
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.
Proportional Modified EBITDA of equity-method investments reflects a $19 million decrease from Aux Sable primarily due to lower NGL margins and certain contingency loss accruals, partially offset by an $11 million increase from OPPL associated with higher transportation volumes.
2014 vs. 2013
Modified EBITDA decreased in 2014 compared to 2013 primarily due to $192 million lower Olefin product margins including $196 million lower product margins at our Geismar plant as a result of the Geismar Incident and $52 million lower marketing margins primarily due to declines in NGL prices while product was in transit in 2014 compared to gains in 2013. The 2014 losses were driven by significant declines in NGL prices during the fourth quarter of 2014. These decreases are partially offset by higher insurance proceeds related to the Geismar Incident.
Product sales decreased primarily due to:
A $252 million decrease in olefin sales due to $256 million of lower sales volumes, partially offset by $4 million higher per-unit sales prices. Lower sales volumes are primarily due to a $295 million decrease in volumes at our Geismar facility due to the lack of production in 2014 as a result of the Geismar Incident, partially offset by a $32 million increase in volumes at our RGP Splitter primarily due to a third-party storage facility being back in operation in the fourth quarter of 2014 after an outage during the latter part of 2013 and the first part of 2014, which caused us to reduce production during this period (substantially offset in Product costs). These lower volumes were also offset by a net $4 million in higher per-unit sales prices consisting of a $10 million increase in our RGP Splitter per-unit sales prices partially offset by a $6 million decrease in our Canadian alky feedstock per-unit sales prices (substantially offset in Product costs).
A $46 million increase in NGL sales revenues primarily due to new Canadian ethane volumes generated by the ethane recovery project placed in service in December 2013. Non-ethane per-unit sales prices were also higher, partially offset by lower non-ethane sales volumes driven primarily by changes in inventory management of propane and unfavorable changes in the composition of off-gas feedstock.

74



A $46 million increase in marketing revenues due primarily to higher ethane and non-ethane volumes partially offset by lower non-ethane prices (more than offset in Product Costs).
Product costs increased primarily due to:
A $98 million increase in marketing purchases primarily due to increased NGL volumes as well as $27 million in lower of cost or market adjustments in 2014 compared to $3 million in lower of cost or market adjustments in 2013 (partially offset in Product Sales).
A $42 million increase in costs associated with our Canadian NGLs primarily due to new ethane volumes generated by the ethane recovery project and higher natural gas prices, partially offset by lower natural gas volumes associated with the production of non-ethane NGLs.
A $60 million decrease in olefin feedstock purchases primarily due to a $99 million decrease in volumes at our Geismar facility due to the lack of production in 2014 as a result of the Geismar Incident. This decrease is partially offset by a $29 million increase in volumes at our RGP Splitter primarily due to a third-party storage facility being back in operation in the fourth quarter of 2014 after an outage during the latter part of 2013 and the first part of 2014 which caused us to reduce production during this period (more than offset in Product sales), as well as $6 million higher per-unit costs at our RGP Splitter (more than offset in Product sales).
The unfavorable change in Other segment costs and expenses is primarily due to a $16 million increase in 2014 operating expenses primarily associated with the repair of the Geismar plant and the installation of certain safety equipment as well as a $9 million involuntary conversion gain in 2013 related to a 2012 furnace fire at our Geismar plant.
The increase 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. This increase is partially offset by higher covered insurable expenses in excess of our retentions (deductibles).


75



Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
In 2015, we continued to focus upon distributions to unitholders and growth in our businesses through disciplined investments. Examples of this growth included:
Expansion of Transco’s interstate natural gas pipeline system through projects such as Leidy Southeast and Virginia Southside to meet the demand of growth markets;
Our acquisitions of a gathering system in the Eagle Ford shale and an additional 13 percent interest in our equity-method investment in UEOM;
Our commissioning of the Bucking Horse gas processing facility joint venture in the Powder River basin Niobrara Shale.
This growth was funded primarily through cash flow from operations and additional net borrowings.
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:
Firm demand and capacity reservation transportation revenues under long-term contracts;
Fee-based revenues from certain gathering and processing services.
However, we are indirectly exposed to longer duration depressed energy commodity prices and the related impact on drilling activities and volumes available for gathering and processing services.
We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, unitholder distributions, and debt service payments while maintaining a sufficient level of liquidity. In particular, we note that we expect growth capital and investment expenditures to total approximately $2.1 billion in 2016, down approximately $1.2 billion from 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 growth capital and investment expenditures primarily reflect investments 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. We retain the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities. In addition, we expect proceeds from planned asset monetizations in excess of $1 billion during 2016.
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2016. Our internal and external sources of consolidated liquidity to fund working capital requirements, capital and investment expenditures, debt service payments, and distributions to unitholders include:
Cash and cash equivalents on hand;
Cash generated from operations, including cash distributions from our equity-method investees;
Use of our credit facilities and/or commercial paper program;

76



Transco’s recent debt issuance described further below;
Proceeds from planned asset monetizations.
We do not plan to issue public equity or public debt in 2016. We anticipate our more significant uses of cash to be:
Maintenance and expansion capital and investment expenditures;
Interest on long-term debt;
Repayment of current debt maturities;
Quarterly distributions to our unitholders and general partner, including IDRs.
Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures include those previously discussed in Company Outlook. We further note that certain long-term debt originally issued by ACMP totaling $2.9 billion has provisions that would require us to make an offer to repurchase such notes at 101 percent of the principle amount should our credit be downgraded by either Moody’s Investor Service or Standard and Poor’s within a period of ninety days following the completion of the proposed ETC Merger. If we are required to repurchase the notes, we would expect our funding sources to be derived from credit facility borrowings, new debt issuances, additional asset sales, reductions of distributions, and/or equity issuances.
As of December 31, 2015, we had a working capital deficit (current liabilities, inclusive of commercial paper outstanding and long-term debt due within one year, in excess of current assets) of $782 million. Excluding the impact of the $499 million in commercial paper outstanding, which we consider to be a reduction of our credit facility capacity as noted in the table below, our working capital deficit is $283 million. Our available liquidity is as follows:
Available Liquidity
December 31, 2015
 
(Millions)
Cash and cash equivalents
$
96

Capacity available under our $3.5 billion credit facility, less amounts outstanding under our $3 billion commercial paper program (1)
1,691

Capacity available under our short-term credit facility (2)
150

 
$
1,937

__________
(1)
In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. At December 31, 2015, we had $499 million of commercial paper outstanding. The highest amount outstanding under our commercial paper program and credit facility during 2015 was $3.1 billion. At December 31, 2015, we were in compliance with the financial covenants associated with this credit facility and the commercial paper program. See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements for additional information on our credit facility and commercial paper program. Borrowing capacity available under this facility as of February 25, 2016, was $2.507 billion.

(2)
See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements for additional information on our short-term credit facility entered into August 26, 2015 and amended December 23, 2015. Borrowing capacity available under this facility as of February 25, 2016, was $150 million.

On September 24, 2015, we received a special distribution of $396 million from Gulfstream reflecting our proportional share of the proceeds from new debt issued by Gulfstream. The new debt was issued to refinance Gulfstream’s debt maturities. Subsequently, we contributed $248 million to Gulfstream for our proportional share of amounts necessary to fund debt maturities of $500 million due on November 1, 2015. We also expect to contribute our proportional share of amounts necessary to fund debt maturities of $300 million due on June 1, 2016.

77



Incentive Distribution Rights
Williams has agreed to temporarily waive incentive distributions of approximately $2 million per quarter in connection with our acquisition of an approximate 13 percent additional interest in UEOM on June 10, 2015. The waiver will continue through the quarter ending September 30, 2017.
Williams is required to pay us a $428 million termination fee associated with the Termination Agreement (as described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements), which will settle through a reduction of quarterly incentive distributions payable to Williams (such reduction not to exceed $209 million per quarter). The November 2015 and February 2016 distributions to Williams were each reduced by $209 million related to this termination fee.
Debt Issuances and Retirements
On January 22, 2016, Transco issued $1 billion of 7.85 percent senior notes due 2026 to investors in a private debt placement. Transco intends to use the net proceeds from the offering to repay debt and to fund capital expenditures.
In December 2015, we borrowed $850 million on a variable interest rate loan with certain lenders due 2018. We used the proceeds for working capital, capital expenditures, and for general partnership purposes.
On April 15, 2015, we paid $783 million, including a redemption premium, to early retire $750 million of 5.875 percent senior notes due 2021.
On March 3, 2015, we completed a public offering of $1.25 billion of 3.6 percent senior unsecured notes due 2022, $750 million of 4 percent senior unsecured notes due 2025, and $1 billion of 5.1 percent senior unsecured notes due 2045. We used the net proceeds to repay amounts outstanding under our commercial paper program and credit facility, to fund capital expenditures, and for general partnership purposes.
We retired $750 million of 3.8 percent senior unsecured notes that matured on February 15, 2015.
On June 27, 2014, Pre-merger WPZ completed a public offering of $750 million of 3.9 percent senior unsecured notes due 2025 and $500 million of 4.9 percent senior unsecured notes due 2045. Pre-merger WPZ used the net proceeds to repay amounts outstanding under our commercial paper program, to fund capital expenditures, and for general partnership purposes.
On March 4, 2014, Pre-merger WPZ completed a public offering of $1 billion of 4.3 percent senior unsecured notes due 2024 and $500 million of 5.4 percent senior unsecured notes due 2044. Pre-merger WPZ used the net proceeds to repay amounts outstanding under our commercial paper program, to fund capital expenditures, and for general partnership purposes.
Shelf Registration
On February 25, 2015, we filed a shelf registration statement, as a well-known seasoned issuer and we also filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in us having an aggregate offering price of up to $1 billion. These sales will be made over a period of time and from time to time in transactions at prices which are market prices prevailing at the time of sale, prices related to market price or at negotiated prices. Such sales will be made pursuant to an equity distribution agreement between us and certain banks who may act as sales agents or purchase for their own accounts as principals. During 2015, 1,790,840 common units were issued under this registration. The net proceeds of $59 million were used for general partnership purposes.
Distributions from Equity-Method Investees
The organizational documents of entities in which we have an equity-method interest generally require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. See Note 6 – Investing Activities of Notes to Consolidated Financial Statements for our more significant equity-method investees.

78



Credit Ratings
Our ability to borrow money is impacted by our credit ratings. Our current ratings are as follows:
Rating Agency
 
Outlook
 
Senior Unsecured
Debt Rating
 
Corporate Credit Rating
Standard & Poor’s
 
Negative
 
BBB-
 
BBB-
Moody’s Investors Service
 
Negative
 
Baa3
 
N/A
Fitch Ratings
 
Stable
 
BBB-
 
N/A
In December 2015 and January 2016, the credit ratings agencies lowered our ratings and Standard & Poor’s and Fitch Ratings revised the outlook, but we maintained investment grade ratings. In February 2016, Standard & Poor’s affirmed our ratings and revised the outlook. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A further downgrade of our credit rating might increase our future cost of borrowing and would require us to provide additional collateral to third parties, negatively impacting our available liquidity. As of December 31, 2015, we estimated that a downgrade to a rating below investment grade could require us to provide up to $271 million in additional collateral of either cash or letters of credit with third parties.
Cash Distributions to Unitholders
We paid a cash distribution of $0.85 per unit on February 12, 2016, on our outstanding common units to unitholders of record at the close of business on February 5, 2016. (See Note 4 – Allocation of Net Income (Loss) and Distributions of Notes to Consolidated Financial Statements.)
Sources (Uses) of Cash
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Net cash provided (used) by:
 
 
 
 
 
Operating activities
$
2,661

 
$
2,345

 
$
2,169

Financing activities
215

 
1,585

 
1,595

Investing activities
(2,951
)
 
(3,869
)
 
(3,736
)
Increase (decrease) in cash and cash equivalents
$
(75
)
 
$
61

 
$
28

Operating activities
The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Impairment of goodwill, Impairment of equity-method investments and Depreciation and amortization. Our Net cash provided by operating activities in 2015 increased from 2014 primarily due to the impact of net favorable changes in operating working capital and the absence of contributions from ACMP for the first six months of 2014.
Our Net cash provided by operating activities in 2014 increased from 2013 primarily due to increased proceeds from insurance recoveries on the Geismar Incident, proceeds from a contingency settlement in 2014, and contributions from consolidating ACMP for the second half of 2014. These changes were partially offset by net unfavorable changes in operating working capital, lower olefins production margins, and increased interest payments of debt.
Financing activities
Significant transactions include:
2015
$306 million of net payments of commercial paper;

79



$3.842 billion net received from our debt offerings;
$1.533 billion paid on our debt retirements;
$3.832 billion received from our credit facility borrowings;
$3.162 billion paid on our credit facility borrowings;
$2.686 billion, including $1.846 billion to Williams, related to quarterly cash distributions paid to limited partner unitholders and the general partner;
$87 million paid for dividend and distributions to noncontrolling interests;
$111 million received in contributions from noncontrolling interests;
$396 million special distribution from Gulfstream;
$248 million contribution to Gulfstream for repayment of debt.
2014
$572 million net proceeds received from commercial paper issuances;
$2.74 billion net proceeds received from our debt offerings;
$1.646 billion received from credit facility borrowings;
$1.156 billion paid on credit facility borrowings;
$2.448 billion, including $1.867 billion to Williams, related to quarterly cash distributions paid to limited partner unitholders and our general partner;
$243 million paid for dividends and distributions to noncontrolling interests;
$334 million received in contributions from noncontrolling interests.
2013
$224 million net proceeds received from commercial paper issuances;
$1.705 billion received from credit facility borrowings;
$994 million net proceeds received from our November 2013 public offering of $600 million of 4.5 percent senior unsecured notes due 2023 and $400 million of 5.8 percent senior unsecured notes due 2043;
$2.08 billion paid on credit facility borrowings;
$1.962 billion received from our equity offerings, including $143 million received from Williams, which was used to repay credit facility borrowings;
$1.846 billion, including $1.376 billion to Williams, related to quarterly cash distributions paid to limited partner unitholders and our general partner;
$398 million received in contributions from noncontrolling interests;

80



$221 million in net contributions from Williams related to the Canada Acquisition.
Investing activities
Significant transactions include:
2015
$2.795 billion in capital expenditures;
$112 million paid to purchase a gathering system comprised of approximately 140 miles of pipeline and a sour gas compression facility in the Eagle Ford shale;
Purchases of and contributions to our equity-method investments of $594 million.
2014
$3.692 billion in capital expenditures;
Purchases of and contributions to our equity-method investments of $468 million.
2013
$3.316 billion in capital expenditures;
Purchases of and contributions to our equity-method investments of $439 million.
Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in Note 3 – Variable Interest Entities, Note 11 – Property, Plant and Equipment, Note 13 – Debt, Banking Arrangements, and Leases, Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk, and Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.
Contractual Obligations
The table below summarizes the maturity dates of our contractual obligations at December 31, 2015: 
 
2016
 
2017 - 2018
 
2019 - 2020
 
Thereafter
 
Total
 
(Millions)
Long-term debt: (1)
 
 
 
 
 
 
 
 
 
Principal (2)
$
375

 
$
2,135

 
$
3,410

 
$
13,218

 
$
19,138

Interest
835

 
1,529

 
1,408

 
6,398

 
10,170

Commercial paper
499

 

 

 

 
499

Capital leases
1

 

 

 

 
1

Operating leases
82

 
109

 
68

 
99

 
358

Purchase obligations (3)
1,187

 
283

 
276

 
336

 
2,082

Other obligations (4)
2

 
2

 
1

 

 
5

Total
$
2,981

 
$
4,058

 
$
5,163

 
$
20,051

 
$
32,253

____________
(1)
Includes the borrowings outstanding under our credit facility, but does not include any related variable-rate interest payments.

81



(2)
The 2016 amount includes $200 million that is presented as long-term debt at December 31, 2015 on the Consolidated Balance Sheet, due to our intent and ability to refinance.
(3)
Includes approximately $630 million in open property, plant, and equipment purchase orders. Includes an estimated $269 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2015 prices. This obligation is part of an overall exchange agreement whereby volumes we transport on OPPL are sold at a third-party fractionator near Conway, Kansas, and we are subsequently obligated to purchase ethane volumes at Mont Belvieu. The purchased ethane volumes may be utilized or resold at comparable prices in the Mont Belvieu market. Includes an estimated $411 million long-term NGL purchase obligation with index-based pricing terms that primarily supplies a third party at its plant and is valued in this table at a price calculated using December 31, 2015 prices. Any excess purchased volumes may be sold at comparable market prices. In addition, we have not included certain natural gas life-of-lease contracts for which the future volumes are indeterminable. We have not included commitments, beyond purchase orders, for the acquisition or construction of property, plant, and equipment or expected contributions to our jointly owned investments. (See Company Outlook – Expansion Projects.)
(4)
We have not included income tax liabilities in the table above. See Note 8 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of income taxes.
Effects of Inflation
Our operations have historically not been materially affected by inflation. Approximately 37 percent of our gross property, plant, and equipment is comprised of our interstate natural gas pipeline assets. They are subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to replace existing assets. Cost-based regulations, along with competition and other market factors, may limit our ability to recover such increased costs. For our gathering and processing assets, operating costs are influenced to a greater extent by both competition for specialized services and specific price changes in crude oil and natural gas and related commodities than by changes in general inflation. Crude oil, natural gas, and NGL prices are particularly sensitive to the market perceptions concerning the supply and demand balance in the near future, as well as general economic conditions. However, our exposure to certain of these price changes is reduced through the fee-based nature of certain of our services and the use of hedging instruments.
Environmental
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and/or remedial processes at certain sites, some of which we currently do not own (See Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $15 million, all of which are included in Other accrued liabilities and Regulatory liabilities, deferred income, and other on the Consolidated Balance Sheet at December 31, 2015. We will seek recovery of approximately $8 million of these accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2015, we paid approximately $4 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $4 million in 2016 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At December 31, 2015, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.
In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. In May 2012, the EPA completed designation of new eight-hour ozone nonattainment areas. Several Transco facilities are located in 2008 ozone nonattainment areas. In December 2014, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels and subsequently finalized a rule on October 1, 2015. We are

82



monitoring the rule's implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. To date, no federal actions have been proposed to mandate additional emission controls at these facilities. Pursuant to pending state regulatory actions associated with implementation of the 2008 ozone standard, we anticipate that some facilities may be subject to increased controls within five years. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net on the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet the regulations.
On January 22, 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. On January 20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO2 NAAQS and thus designated all areas of the country as “unclassifiable/attainment.” Also, at that time the EPA noted its plan to deploy an expanded NO2 monitoring network beginning in 2013. However on October 5, 2012, the EPA proposed a graduated implementation of the monitoring network between January 1, 2014 and January 1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO2 NAAQS. Until that time, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 standard. Because we are unable to predict the outcome of the EPA’s or states’ future assessment using the new monitoring network, we are unable to estimate the cost of additions that may be required to meet this regulation.
Our interstate natural gas pipelines consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates.

83



Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio is primarily comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Any borrowings under the credit facilities and any issuances under the commercial paper program could be at a variable interest rate and could expose us to the risk of increasing interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected lives of our operating assets. (See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)
The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December 31, 2015 and 2014. Long-term debt in the tables represents principal cash flows, net of (discount) premium and debt issuance costs, and weighted-average interest rates by expected maturity dates. The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings.
 
 
2016
 
2017
 
2018
 
2019
 
2020
 
Thereafter(1)
 
Total
 
Fair Value December 31, 2015
 
 
(Millions)
Long-term debt, including current portion: (2)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed rate
 
$
375
(*)
 
$
785

 
$
500

 
$

 
$
2,100

 
$
13,256

 
$
17,016

 
$
13,828

Interest rate
 
5.0
%
 
4.9
%
 
4.8
%
 
4.8
%
 
4.8
%
 
5.2
%
 
 
 
 
Variable rate
 
$

 
$

 
$
850

 
$

 
$
1,310

 
$

 
$
2,160

 
$
2,160

Interest rate (3)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commercial paper:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Variable rate
 
$
499

 
$

 
$

 
$

 
$

 
$

 
$
499

 
$
499

Interest rate (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
_____________
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(*) $200 million presented as long-term debt at December 31, 2015, due to our intent and ability to refinance.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter(1)
 
Total
 
Fair Value December 31, 2014
 
 
(Millions)
Long-term debt, including current portion: (2)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed rate
 
$
750
(**)
 
$
375

 
$
785

 
$
500

 
$

 
$
13,201

 
$
15,611

 
$
15,967

Interest rate
 
5.1
%
 
5.1
%
 
5.0
%
 
5.0
%
 
4.9
%
 
5.1
%
 
 
 
 
Variable rate
 
$

 
$

 
$

 
$
640

 
$

 
$

 
$
640

 
$
640

Interest rate (3)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commercial paper:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Variable rate
 
$
798

 
$

 
$

 
$

 
$

 
$

 
$
798

 
$
798

Interest rate (4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
_____________
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(**) Presented as long-term debt at December 31, 2014, due to our intent and ability to refinance.
______________
(1)
Includes unamortized discount / premium and debt issuance costs.
(2)
Excludes capital leases.
(3)
The weighted-average interest rates for our $1.3 billion credit facility borrowing and our $850 million term loan were 1.63 percent and 1.85 percent at December 31, 2015, respectively. The weighted-average interest rate for our $640 million credit facility borrowing was 2.42 percent at December 31, 2014.

84



(4)
The weighted-average interest rate was 0.92 percent at both December 31, 2015 and 2014.
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of NGLs, olefins, and natural gas, as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts, and limited proprietary trading activities. Our management of the risks associated with these market fluctuations includes maintaining a conservative capital structure and sufficient liquidity, as well as using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. At December 31, 2015 and 2014, our derivative activity was not material. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
Foreign Currency Risk
Our foreign operations, whose functional currency is the local currency, are located in Canada. Net assets of our foreign operations were approximately $916 million and $992 million at December 31, 2015 and 2014, respectively. These investments have the potential to impact our financial position due to fluctuations in the local currency arising from the process of translating the local functional currency into the U.S. dollar. As an example, a 20 percent change in the functional currency against the U.S. dollar would have changed Total partners’ equity by approximately $183 million and approximately $198 million at December 31, 2015 and 2014, respectively.



85



Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors of WPZ GP LLC,
General Partner of Williams Partners L.P.
and the Limited Partners of Williams Partners L.P.

We have audited the accompanying consolidated balance sheet of Williams Partners L.P. (the “Partnership”) as of December 31, 2015 and 2014, and the related consolidated statements of comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Gulfstream Natural Gas System, L.L.C. (“Gulfstream”) (a limited liability corporation in which the Partnership has a 50 percent interest). In the consolidated financial statements, the Partnership’s investment in Gulfstream was $293 million and $317 million, respectively, as of December 31, 2015 and 2014, and the Partnership’s equity earnings in the net income of Gulfstream were $65 million, $65 million and $67 million, respectively, for each of the three years in the period ended December 31, 2015. Gulfstream’s financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Gulfstream, is based solely on the report of the other auditors.

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

In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Williams Partners L.P. at December 31, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Williams Partners L.P.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 26, 2016 expressed an unqualified opinion thereon.


/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 26, 2016








86



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of Gulfstream Natural Gas System, L.L. C.
We have audited the balance sheets of Gulfstream Natural Gas System, L.L.C. as of December 31, 2015 and 2014, and the related statements of operations, comprehensive income, members’ equity, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream Natural Gas System, L.L.C. as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP
Houston, Texas
February 26, 2016





87



Williams Partners L.P.
Consolidated Statement of Comprehensive Income (Loss)
 
 
Years Ended December 31,
 
 
2015
 
2014
 
2013
 
(Millions, except per-unit amounts)
Revenues:
 
 
 
 
 
 
Service revenues
 
$
5,135


$
3,888

 
$
2,914

Product sales
 
2,196


3,521

 
3,921

Total revenues
 
7,331


7,409

 
6,835

Costs and expenses:
 



 
 
Product costs
 
1,779


3,016

 
3,027

Operating and maintenance expenses
 
1,625


1,277

 
1,080

Depreciation and amortization expenses
 
1,702


1,151

 
791

Selling, general, and administrative expenses
 
684


633

 
519

Impairment of goodwill
 
1,098

 

 

Net insurance recoveries – Geismar Incident
 
(126
)
 
(232
)
 
(40
)
Other (income) expense – net
 
186


(45
)
 
51

Total costs and expenses
 
6,948


5,800

 
5,428

Operating income
 
383


1,609

 
1,407

Equity earnings (losses)
 
335


228

 
104

Impairment of equity-method investments
 
(1,359
)
 

 

Other investing income (loss) – net
 
2

 
2

 
(1
)
Interest incurred

(864
)

(683
)
 
(477
)
Interest capitalized

53


121

 
90

Other income (expense) – net
 
93


36

 
26

Income (loss) before income taxes
 
(1,357
)
 
1,313

 
1,149

Provision (benefit) for income taxes
 
1

 
29

 
30

Net income (loss)
 
(1,358
)

1,284

 
1,119

Less: Net income attributable to noncontrolling interests
 
91


96

 
3

Net income (loss) attributable to controlling interests
 
$
(1,449
)

$
1,188

 
$
1,116

Allocation of net income (loss) for calculation of earnings per common unit:
 
 
 
 
 
 
Net income (loss) attributable to controlling interests
 
$
(1,449
)
 
$
1,188

 
$
1,116

Allocation of net income (loss) to general partner
 
384

 
756

 
505

Allocation of net income (loss) to Class B units
 
(46
)
 

 

Allocation of net income (loss) to Class D units
 
68

 
73

 

Allocation of net income (loss) to common units
 
$
(1,855
)
 
$
359

 
$
611

Basic and diluted earnings (loss) per common unit:
 
 
 
 
 
 
Net income (loss) per common unit
 
$
(3.27
)
 
$
0.99

 
$
1.76

Weighted average number of common units outstanding (thousands)
 
567,275

 
361,968

 
346,307

Cash distributions per common unit
 
$
3.4000

 
$
3.5995

 
$
3.4800

Other comprehensive income (loss):
 
 
 
 
 
 
Cash flow hedging activities:
 
 
 
 
 
 
Net unrealized gain (loss) from derivative instruments
 
$
6

 
$
(1
)
 
$
1

Reclassifications into earnings of net derivative instruments (gain) loss
 
(7
)
 

 

Foreign currency translation adjustments
 
(173
)
 
(89
)
 
(56
)
Other comprehensive income (loss)
 
(174
)
 
(90
)
 
(55
)
Comprehensive income (loss)
 
(1,532
)
 
1,194

 
1,064

Less: Comprehensive income attributable to noncontrolling interests
 
91

 
96

 
3

Comprehensive income (loss) attributable to controlling interests
 
$
(1,623
)
 
$
1,098

 
$
1,061


See accompanying notes.

88



Williams Partners L.P.
Consolidated Balance Sheet
 
December 31,
 
2015
 
2014
 
(Millions)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
96

 
$
171

Accounts and notes receivable (net of allowance of $3 at December 31, 2015 and $0 at December 31, 2014)
1,026

 
905

Inventories
127

 
231

Other current assets
190

 
198

Total current assets
1,439

 
1,505

Investments
7,336

 
8,399

Property, plant, and equipment – net
28,600

 
27,322

Goodwill
47

 
1,120

Other intangible assets – net of accumulated amortization
9,969

 
10,451

Regulatory assets, deferred charges, and other
479

 
451

Total assets
$
47,870

 
$
49,248

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable:
 
 
 
Trade
$
648

 
$
808

Affiliate
141

 
137

Accrued interest
231

 
215

Asset retirement obligations
57

 
40

Other accrued liabilities
469

 
392

Long-term debt due within one year
176

 
4

Commercial paper
499

 
798

Total current liabilities
2,221

 
2,394

Long-term debt
19,001

 
16,252

Asset retirement obligations
857

 
791

Deferred income tax liabilities
119

 
133

Regulatory liabilities, deferred income, and other
1,066

 
993

Contingent liabilities and commitments (Note 17)


 

Equity:
 
 
 
Partners’ equity:
 
 
 
Common units (588,546,022 and 362,556,333 units outstanding at December 31, 2015 and 2014, respectively)
19,730

 
10,367

Class B units (14,784,015 units outstanding as of December 31, 2015)
771

 

Class D units (21,574,035 units outstanding at December 31, 2014)

 
1,011

General partner
2,552

 
9,214

Accumulated other comprehensive income (loss)
(172
)
 
2

Total partners’ equity
22,881

 
20,594

Noncontrolling interests in consolidated subsidiaries
1,725

 
8,091

Total equity
24,606

 
28,685

Total liabilities and equity
$
47,870

 
$
49,248

 
See accompanying notes.

89



Williams Partners L.P.
Consolidated Statement of Changes in Equity

 
Williams Partners L.P.
 
 
 
 
 
Limited Partners
 
 
 
 
 
 
 
 
 
 
 
Common
Units
 
Class B Units
 
Class D Units
 
General
Partner
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total Partners’ Equity
 
Noncontrolling
Interests
 
Total
Equity
 
(Millions)
Balance – December 31, 2012
$
10,372

 
$

 
$

 
$
(842
)
 
$
147

 
$
9,677

 
$
14

 
$
9,691

Net income (loss)
660

 

 

 
456

 

 
1,116

 
3

 
1,119

Other comprehensive income (loss)

 

 

 

 
(55
)
 
(55
)
 

 
(55
)
Cash distributions
(1,422
)
 

 

 
(424
)
 

 
(1,846
)
 

 
(1,846
)
Contributions from The Williams Companies, Inc.- net (Note 1)

 

 

 
221

 

 
221

 

 
221

Sales of common units (Note 14)
1,962

 

 

 

 

 
1,962

 

 
1,962

Contributions from general partner

 

 

 
78

 

 
78

 

 
78

Contributions from noncontrolling interests

 

 

 

 

 

 
398

 
398

Other
24

 

 

 
(25
)
 

 
(1
)
 

 
(1
)
   Net increase (decrease) in equity
1,224

 

 

 
306

 
(55
)
 
1,475

 
401

 
1,876

Balance – December 31, 2013
$
11,596

 
$

 
$

 
$
(536
)
 
$
92

 
$
11,152

 
$
415

 
$
11,567

Net income (loss)
354

 

 
62

 
772

 

 
1,188

 
96

 
1,284

Other comprehensive income (loss)

 

 

 

 
(90
)
 
(90
)
 

 
(90
)
Cash distributions
(1,706
)
 

 

 
(742
)
 

 
(2,448
)
 

 
(2,448
)
Contributions from The Williams Companies, Inc.- net (Note 1)

 

 

 
10,703

 

 
10,703

 
7,502

 
18,205

Sales of common units (Note 14)
55

 

 

 

 

 
55

 

 
55

Issuance of Class D units in common control transaction (Note 1)

 

 
1,017

 
(1,017
)
 

 

 

 

Beneficial conversion feature of Class D units
117

 

 
(117
)
 

 

 

 

 

Amortization of beneficial conversion feature of Class D units (Note 4)
(49
)
 

 
49

 

 

 

 

 

Contributions from general partner

 

 

 
13

 

 
13

 

 
13

Distributions to noncontrolling interests

 

 

 

 

 

 
(243
)
 
(243
)
Contributions from noncontrolling interests

 

 

 

 

 

 
334

 
334

Other

 

 

 
21

 

 
21

 
(13
)
 
8

   Net increase (decrease) in equity
(1,229
)
 

 
1,011

 
9,750

 
(90
)
 
9,442

 
7,676

 
17,118

Balance – December 31, 2014
$
10,367

 
$

 
$
1,011

 
$
9,214

 
$
2

 
$
20,594

 
$
8,091

 
$
28,685

Net income (loss)
(1,988
)
 
(52
)
 
1

 
590

 

 
(1,449
)
 
91

 
(1,358
)
Other comprehensive income (loss)

 

 

 

 
(174
)
 
(174
)
 

 
(174
)
Contributions from The Williams Companies, Inc. - net (Note 1)
12,254

 
823

 

 
(6,573
)
 

 
6,504

 
(6,484
)
 
20

Sales of common units (Note 14)
59

 

 

 

 

 
59

 

 
59

Amortization of beneficial conversion feature of Class D units (Note 4)
(68
)
 

 
68

 

 

 

 

 

Conversion of Class D units to common units (Note 4)
1,080

 

 
(1,080
)
 

 

 

 

 

Cash distributions
(1,995
)
 

 

 
(691
)
 

 
(2,686
)
 

 
(2,686
)
Contributions from general partner

 

 

 
14

 

 
14

 

 
14

Contributions from noncontrolling interests

 

 

 

 

 

 
111

 
111

Distributions to noncontrolling interests

 

 

 

 

 

 
(87
)
 
(87
)
Other
21

 

 

 
(2
)
 

 
19

 
3

 
22

   Net increase (decrease) in equity
9,363

 
771

 
(1,011
)
 
(6,662
)
 
(174
)
 
2,287

 
(6,366
)
 
(4,079
)
Balance – December 31, 2015
$
19,730

 
$
771

 
$

 
$
2,552

 
$
(172
)
 
$
22,881

 
$
1,725

 
$
24,606

See accompanying notes.

90



Williams Partners L.P.
Consolidated Statement of Cash Flows

 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
OPERATING ACTIVITIES:
 
 
 
 
 
Net income (loss)
$
(1,358
)
 
$
1,284

 
$
1,119

Adjustments to reconcile to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization
1,702

 
1,151

 
791

Provision (benefit) for deferred income taxes
4

 
25

 
50

Impairment of goodwill
1,098

 

 

Impairment of equity-method investments
1,359

 

 

Impairment of and net (gain) loss on sale of Property, plant, and equipment
150

 
68

 
7

Amortization of stock-based awards
27

 
9

 

Cash provided (used) by changes in current assets and liabilities:
 
 
 
 
 
Accounts and notes receivable
(67
)
 
(169
)
 
21

Inventories
105

 
(36
)
 
(17
)
Other current assets and deferred charges
2

 
(43
)
 
25

Accounts payable
(128
)
 
(42
)
 
(32
)
Accrued liabilities
(15
)
 
(233
)
 
171

Affiliate accounts receivable and payable – net

 
9

 
(1
)
Other, including changes in noncurrent assets and liabilities
(218
)
 
322

 
35

Net cash provided by operating activities
2,661

 
2,345

 
2,169

FINANCING ACTIVITIES:
 
 
 
 
 
Proceeds from (payments of) commercial paper – net
(306
)
 
572

 
224

Proceeds from long-term debt
7,675

 
4,386

 
2,699

Payments of long-term debt
(4,699
)
 
(1,157
)
 
(2,080
)
Proceeds from sales of common units
59

 
55

 
1,962

Contributions from general partner
14

 
13

 
53

Distributions to limited partners and general partner
(2,686
)
 
(2,448
)
 
(1,846
)
Distributions to noncontrolling interests
(87
)
 
(243
)
 

Contributions from noncontrolling interests
111

 
334

 
398

Contributions from The Williams Companies, Inc. – net
20

 
73

 
221

Payments for debt issuance costs
(33
)
 
(24
)
 
(12
)
Special distribution from Gulfstream
396

 

 

Contribution to Gulfstream for repayment of debt
(248
)
 

 

Other – net
(1
)
 
24

 
(24
)
Net cash provided by financing activities
215

 
1,585

 
1,595

INVESTING ACTIVITIES:
 
 
 
 
 
Property, plant, and equipment:
 
 
 
 
 
Capital expenditures (1)
(2,795
)
 
(3,692
)
 
(3,316
)
Net proceeds from dispositions
3

 
34

 
3

Purchase of business
(112
)
 

 

Purchase of business from affiliate

 

 
25

Purchases of and contributions to equity-method investments
(594
)
 
(468
)
 
(439
)
Other – net
547

 
257

 
(9
)
Net cash used by investing activities
(2,951
)
 
(3,869
)
 
(3,736
)
Increase (decrease) in cash and cash equivalents
(75
)
 
61

 
28

Cash and cash equivalents at beginning of year
171

 
110

 
82

Cash and cash equivalents at end of year
$
96

 
$
171

 
$
110

_________

 
 
 
 
 
(1) Increases to property, plant, and equipment
$
(2,649
)
 
$
(3,571
)
 
$
(3,333
)
Changes in related accounts payable and accrued liabilities
(146
)
 
(121
)
 
17

Capital expenditures
$
(2,795
)
 
$
(3,692
)
 
$
(3,316
)
See accompanying notes.

91





Williams Partners L.P.
Notes to Consolidated Financial Statements
 


Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
General
Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or like terms refer to Williams Partners L.P. and its subsidiaries. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations.
We are a Delaware limited partnership whose common units are listed and traded on the New York Stock Exchange. WPZ GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. Williams owns an approximate 58 percent limited partner interest, a 2 percent general partner interest, and incentive distribution rights (IDRs) in us. Our operations are located in the United States and Canada.
Public Unit Exchange
On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby Williams would have acquired all of our publicly held outstanding common units in exchange for shares of Williams’ common stock (Public Unit Exchange).
On September 28, 2015, we entered into a Termination Agreement and Release (Termination Agreement), terminating the Public Unit Exchange. Under the terms of the Termination Agreement, Williams is required to pay us a $428 million termination fee, which will settle through a reduction of quarterly incentive distributions payable to Williams (such reduction not to exceed $209 million per quarter). Our November 2015 and February 2016 distributions to Williams were each reduced by $209 million related to this termination fee.
Williams’ Merger Agreement with Energy Transfer
On September 28, 2015, Williams publicly announced in a press release that it had 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, Williams 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. Immediately following the completion of the ETC Merger, 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 Williams stockholders in the ETC Merger. We expect to retain our current name and remain a publicly traded limited partnership following the ETC Merger.
ACMP Merger
Pursuant to an Agreement and Plan of Merger dated as of October 24, 2014, the general partners of Williams Partners L.P. and Access Midstream Partners, L.P. agreed to combine those businesses and their general partners, with Williams Partners L.P. merging with and into Access Midstream Partners, L.P. and the Access Midstream Partners, L.P. general partner being the surviving general partner (ACMP Merger). Following the completion of the ACMP Merger on February 2, 2015, as further described below, the surviving Access Midstream Partners, L.P. changed its name to Williams Partners L.P. and the name of its general partner was changed to WPZ GP LLC. For the purpose of these financial statements and notes, Williams Partners L.P. (WPZ) refers to the renamed merged partnership, while Pre-merger Access Midstream Partners, L.P. (ACMP) and Pre-merger Williams Partners L.P. (Pre-merger WPZ) refer to the separate partnerships prior to the consummation of the ACMP Merger and subsequent name change.

92





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

In accordance with the terms of the ACMP Merger, each ACMP unitholder received 1.06152 ACMP units for each ACMP unit owned immediately prior to the ACMP Merger. Following this pre-merger split ACMP had 202,564,354 common units and 13,725,843 Class B units outstanding. In conjunction with the ACMP Merger, each Pre-merger WPZ common unit held by the public was exchanged for 0.86672 common units of ACMP. Each Pre-merger WPZ common unit held by Williams was exchanged for 0.80036 common units of ACMP. Prior to the closing of the ACMP Merger, the Class D limited partner units of Pre-merger WPZ, all of which were held by Williams, were converted into Pre-merger WPZ common units on a one-for-one basis pursuant to the terms of the partnership agreement of Pre-merger WPZ. All of the general partner interests of Pre-merger WPZ were converted into general partner interests of ACMP such that the general partner interest of ACMP represents 2 percent of the outstanding partnership interest.
Description of Business
Our operations are located in North America and are organized into the following reportable segments: Access Midstream, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services.
Access Midstream provides 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, the Marcellus Shale region primarily in Pennsylvania and West Virginia, the Utica Shale region of eastern Ohio, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. Access Midstream also includes a 62 percent equity-method investment in Utica East Ohio Midstream, LLC (UEOM), a 50 percent equity-method investment in the Delaware basin gas gathering system in the Mid-Continent region, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 45 percent interest in multiple gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus and Utica shale regions, as well as a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain) and a 58 percent equity-method investment in Caiman Energy II, LLC (Caiman II).
Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (Transco), and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One LLC (Gulfstar One) (a consolidated entity), which is a proprietary floating production system, as well as a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is under development, and a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery).
West is comprised of our gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming and our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline). Effective during the first quarter of 2015, the operations of the Niobrara Shale region that were formerly within the Access Midstream segment were transferred into the West reportable segment. The prior period amounts and disclosures included herein have been recast for this change.
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 pipelines in the Gulf Coast region, an oil sands offgas processing plant located near Fort McMurray, Alberta, and a natural gas liquid (NGL)/olefin fractionation facility and butylene/butane splitter facility at Redwater, Alberta. This segment also includes our 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 Overland Pass Pipeline, LLC (OPPL).

93





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Basis of Presentation
Prior to the ACMP Merger, Williams owned certain limited partnership interests in both Pre-merger WPZ and ACMP, as well as 100 percent of the general partners of both partnerships. Due to the ownership of the general partners, Williams controlled both partnerships. Williams’ control of Pre-merger WPZ began with its inception in 2005, while control of ACMP was achieved upon obtaining an additional 50 percent interest in its general partner effective July 1, 2014. Williams previously acquired 50 percent of the ACMP general partner in a separate transaction in 2012.
ACMP Merger
The ACMP Merger has been accounted for as a combination between entities under common control, with Pre-merger WPZ representing the predecessor entity. As such, the accompanying financial statements represent a continuation of Pre-merger WPZ, the accounting acquirer, except for certain adjustments to give effect to the exchange ratio applied to Pre-merger WPZ’s historically outstanding units. Because the ACMP Merger was between entities under common control, it was treated similar to a pooling of interests whereby the historical results of operations for ACMP were combined with those of Pre-merger WPZ for periods under common control (periods subsequent to July 1, 2014) and the net assets of ACMP were combined at Williams’ historical basis. (See Note 2 – Acquisitions.)
Historical earnings of ACMP prior to the ACMP Merger have been presented herein as allocated to either the capital account of the general partner for interests owned by Williams or to noncontrolling interests for interests held by the public. Thus, there was no change in the total amount of historical earnings attributable to common unitholders. In conjunction with the ACMP Merger, the partners’ equity interests in ACMP have been reclassified out of the capital account of the general partner for interests owned by Williams and noncontrolling interests for interests held by the public and into the capital accounts of common and Class B interests as a Contributions from the Williams Companies, Inc. - net within the Consolidated Statement of Changes in Equity.
Canada Acquisition
In February 2014, Pre-merger WPZ acquired certain Canadian operations from Williams (Canada Acquisition) for total consideration of $56 million of cash (including a $31 million post-closing adjustment paid in the second quarter of 2014), 25,577,521 Pre-merger WPZ Class D limited-partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. In lieu of cash distributions, the Class D units received quarterly distributions of additional paid-in-kind Class D units. This common control acquisition was treated similar to a pooling of interests whereby the historical results of operations were combined with ours for all periods presented and the acquired assets and liabilities were combined with ours at their historical amounts. These Canadian operations are reported in our NGL & Petchem Services segment.
In October 2014, a purchase price adjustment was finalized whereby Pre-merger WPZ received $56 million in cash from Williams in the fourth quarter of 2014 and Williams waived $2 million in payments on its IDRs with respect to Pre-merger WPZ’s November 2014 distribution.
The Canadian operations previously participated in Williams’ cash management program under a credit agreement with Williams. Net changes in amounts due to/from Williams prior to the Canada Acquisition, along with the cash consideration paid for the Canada Acquisition, are reflected within Contributions from the Williams Companies, Inc. - net within the Consolidated Statement of Changes in Equity.
Other
In the first quarter of 2013, Pre-merger WPZ received $25 million in cash from Williams and Williams waived $4 million in payments on its IDRs with respect to Pre-merger WPZ’s May 2013 distribution related to a working capital adjustment associated with a 2012 acquisition.

94





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain ventures in which we own an undivided interest. Management’s judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:
Determining whether an entity is a variable interest entity (VIE);

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

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

Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities.
We apply the equity method of accounting to investments over which we exercise significant influence but do not control.
Common control transactions
Entities and assets acquired from Williams and its affiliates are accounted for as common control transactions whereby the net assets acquired are combined with ours at their historical amounts. If any cash consideration transferred to Williams in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital transaction with our general partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any cash consideration transferred and limited partner units are also issued as consideration, then the limited partner units are recorded at an amount equal to the excess of the carrying value of the net assets acquired over any cash consideration transferred. To the extent that such transactions require prior periods to be recast, historical net equity amounts prior to the transaction date are reflected in the account of the general partner or noncontrolling interests, if applicable. Cash consideration up to the carrying value of net assets acquired is presented as an investing activity in our Consolidated Statement of Cash Flows. Cash consideration in excess of the carrying value of net assets acquired is presented as a financing activity in our Consolidated Statement of Cash Flows.
Equity-method investment basis differences
Differences between the cost of our equity-method investments and our underlying equity in the net assets of investees are accounted for as if the investees were consolidated subsidiaries. Equity earnings (losses) in the Consolidated Statement of Comprehensive Income (Loss) includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

95





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Significant estimates and assumptions include:
Impairment assessments of investments, property, plant, and equipment, goodwill, and other identifiable intangible assets;
Litigation-related contingencies;
Environmental remediation obligations;
Depreciation and/or amortization of equity-method investment basis differences;
Asset retirement obligations;
Acquisition related purchase price allocations.
These estimates are discussed further throughout these notes.
Regulatory accounting
Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, our management has determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations”, to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, and pension and other postretirement benefits. Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2015 and 2014 are as follows:

December 31,

2015

2014

(Millions)
Current assets reported within Other current assets
$
84


$
81

Noncurrent assets reported within Regulatory assets, deferred charges, and other
305


289

Total regulated assets
$
389


$
370





Current liabilities reported within Other accrued liabilities
$
4


$
11

Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other
409


349

Total regulated liabilities
$
413


$
360

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

96





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.
Inventory valuation
All Inventories in the Consolidated Balance Sheet are stated at the lower of cost or market. The cost of inventories is primarily determined using the average-cost method.
Property, plant, and equipment
Property, plant, and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.
As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method.
Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Other gains or losses are recorded in Other (income) expense – net included in Operating income in the Consolidated Statement of Comprehensive Income (Loss).
Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment.
We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset as management expects to recover these amounts in future rates. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income (Loss), except for regulated entities, for which the liability is offset by a regulatory asset. The regulatory asset is amortized commensurate with the collection of those costs in rates.
Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium.
Goodwill
Goodwill in the Consolidated Balance Sheet represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting

97





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess. Judgments and assumptions are inherent in our management’s estimates of fair value.
Other intangible assets
Our identifiable intangible assets are primarily related to gas gathering, processing, and fractionation contractual customer relationships. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.
Impairment of property, plant, and equipment, other identifiable intangible assets, and investments
We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.
We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge.
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.
Contingent liabilities
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.
Cash flows from revolving credit facility and commercial paper program
Proceeds and payments related to borrowings under our credit facility are reflected in the financing activities in the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a

98





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 13 – Debt, Banking Arrangements, and Leases.)
Derivative instruments and hedging activities
We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of physical energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets; Regulatory assets, deferred charges, and other; Other accrued liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
Derivative Treatment
 
Accounting Method
Normal purchases and normal sales exception
 
Accrual accounting
Designated in a qualifying hedging relationship
 
Hedge accounting
All other derivatives
 
Mark-to-market accounting
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income (Loss).
For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income (Loss). Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated Statement of Comprehensive Income (Loss) at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management.
For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Comprehensive Income (Loss).

99





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Certain gains and losses on derivative instruments included in the Consolidated Statement of Comprehensive Income (Loss) are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception.
Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis.
Revenue recognition
Revenues
As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.
Service revenues
Revenues from our interstate natural gas pipeline businesses include services pursuant to long-term firm transportation and storage agreements. These agreements provide for a reservation charge based on the volume of a contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for reservation charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges, from both firm and interruptible transportation services and storage injection and withdrawal services, are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility.
Certain revenues from our midstream operations include those derived from natural gas gathering, processing, treating, and compression services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed.
Certain of our gas gathering agreements have minimum volume commitments. If a customer under such an agreement fails to meet its minimum volume commitment for a specified period, generally measured on an annual basis, it is obligated to pay a contractually determined fee based upon the shortfall between actual production volumes and the minimum volume commitment for that period. The revenue associated with minimum volume commitments is recognized in the period that the actual shortfall is determined and is no longer subject to future reduction or offset.
Crude oil gathering and transportation revenues and offshore production handling fees are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available.
Storage revenues from our midstream operations associated with prepaid contracted storage capacity contracts are recognized on a straight-line basis over the life of the contract as services are provided.
Product sales
In the course of providing transportation services to customers of our interstate natural gas pipeline businesses, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances.

100





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

We market NGLs, crude oil, natural gas, and olefins that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing NGLs are recognized when the products have been sold and delivered.
Under our keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.
Our domestic olefins business produces olefins from purchased or produced feedstock and we recognize revenues when the olefins are sold and delivered.
Our Canadian business has processing and fractionation operations where we retain certain NGLs and olefins from an upgrader’s offgas stream and we recognize revenues when the fractionated products are sold and delivered.
Interest capitalized
We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds (equity AFUDC). The latter is included in Other income (expense) – net below Operating income in the Consolidated Statement of Comprehensive Income (Loss). The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.
Employee equity-based awards
We recognize compensation expense on employee equity-based awards, net of estimated forfeitures, on a straight-line basis. (See Note 15 – Equity-Based Compensation.)
Pension and other postretirement benefits
We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 9 – Benefit Plans.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us, and thus paid by us, is based on our share of net periodic benefit cost.
Income taxes
We generally are not a taxable entity for income tax purposes, with the exception of Texas franchise tax and foreign income taxes associated with our Canadian operations. Other income taxes are generally borne by individual partners. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregated difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available to us.
Foreign deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the related assets and liabilities. Our management’s judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.
Earnings (loss) per common unit
We use the two-class method to calculate basic and diluted earnings (loss) per common unit whereby net income (loss), adjusted for items specifically allocated to our general partner, is allocated on a pro-rata basis between unitholders

101





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

and our general partner. Basic and diluted earnings (loss) per common unit are based on the average number of common units outstanding. Diluted earnings (loss) per common unit includes any dilutive effect of nonvested restricted common units determined by the treasury-stock method, unless common unitholders are allocated a loss.
Foreign currency translation
Our foreign subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of such foreign subsidiaries are translated at the spot rate in effect at the applicable reporting date, and the combined statements of comprehensive income (loss) are translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment is recorded as a separate component of AOCI in the Consolidated Balance Sheet.
Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates when the transactions are settled result in transaction gains and losses which are reflected in Other (income) expense – net in the Consolidated Statement of Comprehensive Income (Loss).
Accumulated other comprehensive income (loss)
AOCI is substantially comprised of foreign currency translation adjustments. These adjustments did not impact Net income (loss) in any of the periods presented.
Accounting standards issued but not yet adopted
In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. The new standard clarifies the definition of a lease, requires a dual approach to lease classification similar to current lease classifications, and causes lessees to recognize leases on the balance sheet as a lease liability with a corresponding right-of-use asset for leases with a lease term of more than twelve months. The new standard is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. The new standard requires a modified retrospective transition for capital or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements, but it does not require transition accounting for leases that expire prior to the date of initial application. We are evaluating the impact of the new standard on our consolidated financial statements.
In January 2016, the FASB issued ASU 2016-01 “Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01). ASU 2016-01 addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The new standard is effective for interim and annual periods beginning after December 15, 2017. Early adoption is only permitted for certain applications. We are evaluating the impact of the new standard on our consolidated financial statements and our timing for adoption.
In September 2015, the FASB issued ASU 2015-16 “Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments” (ASU 2015-16). ASU 2015-16 requires an entity to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined; record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date; and present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The new standard is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted for financial statements that have not been issued. We do not expect the new standard will have a significant impact on our consolidated financial statements.

102





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

In July 2015, the FASB issued ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11). ASU 2015-11 simplifies the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, in scope inventory should be measured at the lower of cost and net realizable value. The new standard is effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We measure inventory at the lower of cost or market; upon adoption, we will measure inventory at the lower of cost and net realizable value. We do not expect the new standard will have a material impact on the value of inventory reported in our consolidated financial statements.
In February 2015, the FASB issued ASU 2015-02 “Amendments to the Consolidation Analysis” (ASU 2015-02). ASU 2015-02 alters the models used to determine consolidation conclusions for certain entities, including limited partnerships, and may require additional disclosures. The standard is effective for financial statements issued for interim and annual reporting periods beginning after December 15, 2015, with either retrospective or modified retrospective presentation allowed. We do not expect the new standard will have a significant impact on our consolidated financial statements.
In May 2014, the FASB issued ASU 2014-09 establishing ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016. We continue to evaluate both the impact of this new standard on our consolidated financial statements and the transition method we will utilize for adoption.
Note 2 – Acquisitions
ACMP
As previously discussed in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies, the net assets of Pre-merger WPZ and ACMP have been combined at Williams’ historical basis. Williams’ basis in ACMP reflects its business combination accounting resulting from acquiring control of ACMP on July 1, 2014 (ACMP Acquisition), which, among other things, requires identifiable assets acquired and liabilities assumed to be measured at their acquisition-date fair values.
The valuation techniques used to measure the acquisition-date fair value of ACMP consisted of valuing the limited partner units and general partner interest separately. The limited partner units of ACMP, consisting of common and Class B units, were valued based on ACMP’s closing common unit price at July 1, 2014. The general partner interest, including IDRs, was valued on a noncontrolling basis using an income approach based on a discounted cash flow analysis and a market comparison analysis based on comparable guideline companies and an implied fair value from Williams’ purchase.

103





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

The following table presents the allocation of the acquisition-date fair value of the major classes of the assets acquired, substantially all of which are presented in the Access Midstream segment, liabilities assumed, noncontrolling interest, and equity at July 1, 2014. The fair value of accounts receivable acquired equaled contractual amounts receivable. Changes to the preliminary allocation disclosed in Exhibit 99.1 of the Form 8-K dated May 6, 2015, which were recorded in the first quarter of 2015, reflect an increase of $150 million in Property, plant, and equipment and $25 million in Goodwill, and a decrease of $168 million in Other intangible assets and $7 million in Investments. These adjustments during the measurement period were not considered significant to require retrospective revisions of our financial statements.
 
(Millions)
Accounts receivable
$
168

Other current assets
63

Investments
5,865

Property, plant, and equipment
7,165

Goodwill
499

Other intangible assets
8,841

Current liabilities
(408
)
Debt
(4,052
)
Other noncurrent liabilities
(9
)
Noncontrolling interest in ACMP’s subsidiaries
(958
)
Noncontrolling interest representing ACMP public unitholders
(6,544
)
Equity
(10,630
)

Other intangible assets recognized in the acquisition are related to contractual customer relationships from gas gathering agreements with our customers. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over 30 years during which contractual customer relationships are expected to contribute to our cash flows. As estimated at the time of acquisition, approximately 56 percent of the expected future revenues from these contractual customer relationships were impacted by our ability and intent to renew or renegotiate existing customer contracts. We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the current contract periods (as estimated at the time of acquisition), the weighted-average periods to the next renewal or extension of the existing customer contracts was approximately 17 years.

The following unaudited pro forma Revenues and Net income attributable to controlling interests for the years ended December 31, 2014 and 2013, are presented as if the ACMP Acquisition had been completed on January 1, 2013. These pro forma amounts are not necessarily indicative of what the actual results would have been if the acquisition had in fact occurred on the date or for the periods indicated, nor do they purport to project Revenues or Net income attributable to controlling interests for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transactions or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.
 
 
December 31,
 
 
2014
 
2013
 
 
(Millions)
Revenues
 
$
7,953

 
$
7,881

Net income attributable to controlling interests
 
$
1,376

 
$
1,172



104





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Significant adjustments to pro forma Net income attributable to controlling interests include additional depreciation and amortization expense associated with reflecting the acquired investments, property, plant, and equipment, and other intangible assets at fair value. The adjustments assume estimated useful lives of 30 years.

During the year ended December 31, 2014, ACMP contributed Revenues of $781 million and Net income attributable to controlling interests of $165 million.
Costs incurred by Williams related to this acquisition were $16 million in 2014 and are reported within our Access Midstream segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Comprehensive Income (Loss). Direct transaction costs associated with financing commitments were $9 million in 2014 and reported within Interest incurred in our Consolidated Statement of Comprehensive Income (Loss).
Eagle Ford Gathering System
In May 2015, we acquired a gathering system comprised of approximately 140 miles of pipeline and a sour gas compression facility in the Eagle Ford shale, included in our Access Midstream segment, for $112 million. The acquisition was accounted for as a business combination, and the allocation of the acquisition-date fair value of the major classes of assets acquired includes $80 million of Property, plant, and equipment, at cost and $32 million of Other intangible assets – net of accumulated amortization in the Consolidated Balance Sheet. Changes to the preliminary allocation disclosed in the second quarter of 2015 reflect an increase of $20 million in Property, plant, and equipment, at cost, and a decrease of $20 million in Other intangible assets – net of accumulated amortization.
UEOM Equity-Method Investment
In June 2015, we acquired an additional 13 percent interest in our equity-method investment, UEOM, for $357 million. Following the acquisition we own approximately 62 percent of UEOM. However, we continue to account for this as an equity-method investment because we do not control UEOM due to the significant participatory rights of our partner. In connection with the acquisition of the additional interest, our general partner has agreed to waive approximately $2 million of its IDR payments each quarter through 2017.
Note 3 – Variable Interest Entities
As of December 31, 2015, we consolidate the following VIEs:
Gulfstar One
We own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines which provide production handling and gathering services for the Tubular Bells oil and gas discovery in the eastern deepwater Gulf of Mexico. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance. Construction of an expansion project is underway that will provide production handling and gathering services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico. The expansion project is expected to be in service in the first half of 2016. The current estimate of the total remaining construction cost for the expansion project is approximately $130 million, which we expect will be funded with revenues received from customers and capital contributions from us and the other equity partner on a proportional basis.
Constitution
We own a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its long-term firm transportation contracts, is a VIE. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Constitution’s economic performance. We, as construction manager for Constitution, are responsible for constructing the proposed pipeline connecting our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. We plan to place the

105





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

project in service in the fourth quarter of 2016, assuming timely receipt of all necessary regulatory approvals, and estimate the total remaining cost of the project to be approximately $571 million, which we expect will be funded with capital contributions from us and the other equity partners on a proportional basis.
Cardinal
We own a 66 percent interest in Cardinal Gas Services, L.L.C (Cardinal), a subsidiary that provides gathering services for the Utica region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. We expect to fund future expansion activity with capital contributions from us and the other equity partner on a proportional basis.
Jackalope
We own a 50 percent interest in Jackalope Gas Gathering Services, L.L.C (Jackalope), a subsidiary that provides gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Jackalope’s economic performance. We expect to fund future expansion activity with capital contributions from us and the other equity partner on a proportional basis.
The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of our consolidated VIEs.
 
December 31,
 
 
 
2015
 
2014
 
Classification
 
(Millions)
 
 
Assets (liabilities):
 
 
 
 
 
Cash and cash equivalents
$
70

 
$
113

 
Cash and cash equivalents
Accounts receivable
71

 
52

 
Accounts and notes receivable – net
Other current assets
2

 
3

 
Other current assets
Property, plant, and equipment  net
3,000

 
2,794

 
Property, plant, and equipment – net
Goodwill
47

 
103

 
Goodwill
Other intangible assets  net
1,436

 
1,493

 
Other intangible assets – net of accumulated amortization
Other noncurrent assets

 
14

 
Regulatory assets, deferred charges, and other
Accounts payable
(59
)
 
(48
)
 
Accounts payable – trade
Accrued liabilities
(14
)
 
(36
)
 
Other accrued liabilities
Current deferred revenue
(62
)
 
(45
)
 
Other accrued liabilities
Noncurrent deferred income taxes

 
(13
)
 
Deferred income tax liabilities
Asset retirement obligation
(93
)
 
(94
)
 
Asset retirement obligations, noncurrent
Noncurrent deferred revenue associated with customer advance payments
(331
)
 
(395
)
 
Regulatory liabilities, deferred income, and other

106





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Note 4 – Allocation of Net Income (Loss) and Distributions
The allocation of net income (loss) among our general partner, limited partners, and noncontrolling interests is as follows:
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Allocation of net income to general partner:
 
 
 
 
 
Net income (loss)
$
(1,358
)
 
$
1,284

 
$
1,119

Net income applicable to pre-merger operations allocated to general partner
(2
)
 
(95
)
 

Net income applicable to pre-partnership operations allocated to general partner

 
(15
)
 
(49
)
Net income applicable to noncontrolling interests
(91
)
 
(96
)
 
(3
)
Costs charged directly to the general partner
21

 
1

 
1

Income (loss) subject to 2% allocation of general partner interest
(1,430
)
 
1,079

 
1,068

General partner’s share of net income
2
%
 
2
%
 
2
%
General partner’s allocated share of net income (loss) before items directly allocable to general partner interest
(29
)
 
22

 
21

Priority allocations, including incentive distributions, paid to general partner
638

 
641

 
387

Pre-merger net income allocated to general partner interest
2

 
95

 

Pre-partnership net income allocated to general partner interest

 
15

 
49

Costs charged directly to the general partner
(21
)
 
(1
)
 
(1
)
Net income allocated to general partner’s equity
$
590

 
$
772

 
$
456

 
 
 
 
 
 
Net income (loss)
$
(1,358
)
 
$
1,284

 
$
1,119

Net income allocated to general partner’s equity
590

 
772

 
456

Net income (loss) allocated to Class B limited partners’ equity
(52
)
 

 

Net income allocated to Class D limited partners’ equity (1)
69

 
62

 

Net income allocated to noncontrolling interests
91

 
96

 
3

Net income (loss) allocated to common limited partners’ equity
$
(2,056
)
 
$
354

 
$
660

 
 
 
 
 
 
Adjustments to reconcile Net income (loss) allocated to common limited partners' equity to Allocation of net income (loss) to common units:
 
 
 
 
 
Incentive distributions paid
633

 
640

 
383

Incentive distributions declared (2) (3)
(423
)
 
(626
)
 
(432
)
Impact of unit issuance timing and other
(9
)
 
(9
)
 

Allocation of net income (loss) to common units
$
(1,855
)
 
$
359

 
$
611

 
 
 
 
 
 
____________
(1)
Includes amortization of the beneficial conversion feature associated with the Pre-merger WPZ Class D units of $68 million and $49 million for the years ended December 31, 2015 and 2014, respectively. See following discussion of Class D units.
(2)
On February 12, 2016, we paid a cash distribution of $0.85 per common unit on our outstanding common units to unitholders of record at the close of business on February 5, 2016.
(3)
The 2015 amount reflects the waiver of IDRs associated with the Termination Agreement. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.) The 2014 amount reflects only the portion of the total incentive distribution associated with the Pre-merger WPZ common units exchanged in the ACMP Merger.

107





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Class B Units
The Class B units originated under ACMP and are not entitled to cash distributions. Instead, prior to conversion into common units, the Class B units receive quarterly distributions of additional paid-in-kind Class B units. Effective February 10, 2015, each Class B unit became convertible at the election of either us or the holders of such Class B unit into a common unit on a one-for-one basis. During 2015, we issued a total of 1,058,172 of additional paid-in-kind Class B units associated with quarterly distributions. On February 12, 2016, we issued 558,986 Class B units associated with the fourth-quarter 2015 distribution.
Class D Units
As previously mentioned (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies), a portion of the total consideration for the Canada Acquisition was funded through the issuance of Pre-merger WPZ Class D units to an affiliate of our general partner. The Pre-merger WPZ Class D units were issued at a discount to the market price of Pre-merger WPZ’s common units. The discount represented a beneficial conversion feature and is reflected as an increase in the common unit capital account and a decrease in the Class D capital account on the Consolidated Statement of Changes in Equity. This discount was being amortized through the originally expected first quarter 2016 conversion date, resulting in an increase to the Class D capital account and a decrease to the common unit capital account. The remaining unamortized balance was recognized in the first quarter of 2015 due to the ACMP Merger. All Pre-merger WPZ Class D units were converted into common units in conjunction with the ACMP Merger.
Distributions
The Pre-merger WPZ Class D units were not entitled to cash distributions. Instead, prior to conversion into Pre-merger WPZ common units, the Pre-merger WPZ Class D units received quarterly distributions of additional paid-in-kind Pre-merger WPZ Class D units. During 2014, we issued 1,377,893 Pre-merger WPZ Class D units as the paid-in-kind Class D distributions.
Note 5 – Related Party Transactions
Reimbursement of Expenses of Our General Partner
The employees of our operated assets are employees of Williams. Williams directly charges us for the payroll and benefit costs associated with operations employees and carries the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement, medical plans, and paid time off. Our share of the costs is charged to us through affiliate billings and reflected in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income (Loss) and Property, plant, and equipment – net in the Consolidated Balance Sheet.
In addition, employees of Williams provide general and administrative services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant, and equipment; and payroll. Our share of direct and allocated administrative expenses is reflected in Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income (Loss) and Property, plant, and equipment – net in the Consolidated Balance Sheet.
In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams.


108





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Transactions with Affiliates and Equity-Method Investees
Product costs, in the Consolidated Statement of Comprehensive Income (Loss), include charges for the following types of transactions with equity-method investees:
Purchases of NGLs for resale from Discovery.
Payments to OPPL for transportation of NGLs from certain natural gas processing plants.
Summary of the related party transactions discussed in all sections above. 
 
 
Years Ended December 31,
 
 
2015
 
2014
 
2013
 
 
(Millions)
Product costs
 
$
169

 
$
186

 
$
147

Operating and maintenance expenses - employee costs

498


413


339

Selling, general, and administrative expenses:
 
 
 
 
 
 
Employee direct costs
 
368

 
331

 
270

Employee allocated costs
 
195

 
171

 
169

HB Construction Company Ltd., a subsidiary of Williams, provides construction services to us. Charges for these construction services as well as other capitalized payroll and benefit costs charged by Williams described above are capitalized within Property, plant, and equipment – net in the Consolidated Balance Sheet and totaled $187 million and $81 million during December 2015 and 2014, respectively.
The Accounts payable — affiliate in the Consolidated Balance Sheet represents the payable positions that result from the transactions with affiliates discussed above. We also have $12 million and $13 million in Accounts payable — trade in the Consolidated Balance Sheet with our equity-method investees at December 31, 2015 and 2014, respectively.
Operating Agreements with Equity-Method Investees
We have operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. Williams supplied a portion of these services, primarily those related to employees since we do not have any employees, to certain equity-method investees. The total gross charges to equity-method investees for these fees included in the Consolidated Statement of Comprehensive Income (Loss) are $64 million, $65 million, and $67 million for the years ended December 31, 2015, 2014, and 2013, respectively.
Omnibus Agreement
Under this agreement, Williams is obligated to reimburse us for certain items including (i) maintenance capital expenditure amounts incurred by us or our subsidiaries for certain U.S. Department of Transportation projects, up to a maximum of $50 million, and (ii) an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received by Williams prior to the closing of the contribution transaction for services to be rendered by us in the future at the Devils Tower floating production platform. Net amounts received under this agreement for the years ended December 31, 2015, 2014 and 2013 were $12 million, $11 million, and $12 million, respectively.
We have a contribution receivable from our general partner of $3 million at December 31, 2015, for amounts reimbursable to us under omnibus agreements presented within Total partners’ equity in the Consolidated Balance Sheet.

109





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Acquisitions and Equity Issuances
Basis of Presentation in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies includes related party transactions for the ACMP Merger, Canada Acquisition, and Other. The Canadian operations previously participated in Williams’ cash management program under a credit agreement with Williams. Net changes in amounts due to/from Williams prior to the Canada Acquisition are reflected within Contributions from The Williams Companies, Inc. - net within the Consolidated Statement of Changes in Equity.
Note 14 – Partners’ Capital includes a related party transaction for the sale of Pre-merger WPZ common units to Williams in March 2013.
Board of Directors
A member of Williams’ Board of Directors, who was elected in 2013, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded $111 million, $115 million and $131 million in Service revenues in Consolidated Statement of Comprehensive Income (Loss) from this company for transportation and storage of natural gas for the years ended December 31, 2015, 2014, and 2013, respectively.
Note 6 – Investing Activities
Impairment of equity-method investments in the Consolidated Statement of Comprehensive Income (Loss)
During the third quarter of 2015, we recognized other-than-temporary impairment charges of $458 million and $3 million related to our equity-method investments in the Delaware basin gas gathering system and certain of the Appalachia Midstream Investments, respectively. During the fourth quarter of 2015, we recognized additional impairment charges for these investments of $45 million and $559 million, respectively, as well as impairment charges of $241 million and $45 million associated with our equity-method investments in UEOM and Laurel Mountain, respectively. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)
Equity earnings (losses) in the Consolidated Statement of Comprehensive Income (Loss)
In 2015, we recognized a loss of $19 million associated with our share of underlying property impairments at certain of the Appalachia Midstream Investments. This loss is reported within the Access Midstream segment.
Investments in the Consolidated Balance Sheet
 
December 31,
 
2015
 
2014
 
(Millions)
Appalachia Midstream Investments (1)
$
2,464

 
$
3,033

UEOM – 62% (2)
1,525

 
1,411

Delaware basin gas gathering system – 50%
977

 
1,478

Discovery – 60%
602

 
602

OPPL – 50%
445

 
453

Caiman II – 58%
418

 
432

Laurel Mountain – 69%
391

 
459

Gulfstream – 50%
293

 
317

Other
221

 
214

 
$
7,336

 
$
8,399

____________
(1)
Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 45 percent interest.

110





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

(2)
We acquired an approximate 13 percent additional interest in UEOM in 2015. (See Note 2 – Acquisitions.)
We have differences between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees of $2.4 billion at December 31, 2015 and $3.7 billion at December 31, 2014. These differences primarily relate to our investments in Appalachian Midstream Investments, Delaware basin gas gathering system, and UEOM associated with property, plant, and equipment, as well as customer-based intangible assets and goodwill.
Purchases of and contributions to equity-method investments in the Consolidated Statement of Cash Flows
We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. These transactions increased the carrying value of our investments and included:
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
UEOM (1)
$
357

 
$
57

 
$

Appalachia Midstream Investments
93

 
84

 

Delaware basin gas gathering system
57

 
20

 

Discovery
35

 
106

 
193

Caiman II

 
175

 
192

Other
52

 
26

 
54

 
$
594

 
$
468

 
$
439

____________
(1)
2015 includes purchase of additional interest in UEOM. (See Note 2 – Acquisitions.)

Dividends and distributions
The organizational documents of entities in which we have an equity-method interest generally require distribution of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our investments and included:
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Appalachia Midstream Investments
$
219

 
$
130

 
$

Discovery
116

 
36

 
12

Gulfstream
88

 
81

 
81

OPPL
45

 
27

 
27

UEOM
42

 

 

Caiman II
33

 
13

 

Delaware basin gas gathering system
33

 

 

Laurel Mountain
31

 
39

 

Other
26

 
39

 
34

 
$
633

 
$
365

 
$
154



111





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

In addition, on September 24, 2015, we received a special distribution of $396 million from Gulfstream reflecting our proportional share of the proceeds from new debt issued by Gulfstream. The new debt was issued to refinance Gulfstream’s debt maturities. Subsequently, we contributed $248 million to Gulfstream for our proportional share of amounts necessary to fund debt maturities of $500 million due on November 1, 2015. We also expect to contribute our proportional share of amounts necessary to fund debt maturities of $300 million due on June 1, 2016, as reflected by the accrued liability of $149 million in Other accrued liabilities in the Consolidated Balance Sheet at December 31, 2015.

Summarized Financial Position and Results of Operations of All Equity-Method Investments
 
December 31,
 
2015
 
2014
 
(Millions)
Assets (liabilities):
 
 
 
Current assets
$
773

 
$
599

Noncurrent assets
9,549

 
9,135

Current liabilities
(633
)
 
(850
)
Noncurrent liabilities
(1,450
)
 
(954
)

 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Gross revenue
$
1,707

 
$
1,623

 
$
1,333

Operating income
690

 
534

 
367

Net income
611

 
460

 
291



112





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Note 7 – Other Income and Expenses
The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and expenses in our Consolidated Statement of Comprehensive Income (Loss):
 
 
Years Ended December 31,
 
 
2015
 
2014
 
2013
 
 
(Millions)
Access Midstream
 
 
 
 
 
 
Impairment of certain assets (See Note 16)
 
$
14

 
$
12

 
$

Loss related to sale of certain assets
 

 
10

 

Northeast G&P
 
 
 
 
 
 
Impairment of certain assets (See Note 16)
 
29

 
30

 

Contingency gain settlement (1)
 

 
(154
)
 

Net gain related to partial acreage dedication release
 

 
(12
)
 

Loss associated with a producer claim
 

 

 
25

Atlantic-Gulf
 
 
 
 
 
 
Amortization of regulatory assets associated with asset retirement obligations
 
33

 
33

 
30

Impairment of certain assets
 
5

 
10

 

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

 
(3
)
 
12

Insurance recoveries associated with the Eminence abandonment
 

 

 
(16
)
West
 
 
 
 
 
 
Impairment of certain assets (See Note 16)
 
97

 

 

__________
(1)
In November 2014, we settled a claim arising from the resolution of a contingent gain related to claims associated with the purchase of a business in a prior period. Pursuant to the settlement, we received $154 million in cash, all of which was recognized as a gain in the fourth quarter of 2014.
Geismar Incident
On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant. The incident rendered the facility temporarily inoperable (Geismar Incident).
In 2015, 2014, and 2013, we received $126 million, $246 million, and $50 million, respectively, of insurance recoveries related to the Geismar Incident. These amounts are reported within the NGL & Petchem Services segment and reflected as gains in Net insurance recoveries – Geismar Incident in our Consolidated Statement of Comprehensive Income (Loss). Also, in 2014 and 2013, we incurred $14 million and $10 million, respectively, of covered insurable expenses in excess of our retentions (deductibles) also included in Net insurance recoveries – Geismar Incident and we expensed $13 million within the NGL & Petchem Services segment during 2013 of costs under our insurance deductibles reported in Operating and maintenance expenses in the Consolidated Statement of Comprehensive Income (Loss).
ACMP Acquisition & Merger
Certain ACMP Acquisition and ACMP Merger costs included in Selling, general, and administrative expenses, Operating and maintenance expenses, and Interest incurred in the Consolidated Statement of Comprehensive Income (Loss) are as follows:

113





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Selling, general, and administrative expenses includes $26 million in 2015 and $27 million in 2014 (including $16 million of ACMP Acquisition costs) primarily related to professional advisory fees associated with the ACMP Acquisition and ACMP Merger within the Access Midstream segment.
Selling, general, and administrative expenses includes $9 million in 2015 and $15 million in 2014 of related employee transition costs from the ACMP Merger within the Access Midstream segment.
Operating and maintenance expenses includes $12 million in 2015 and $15 million in 2014 of transition costs from the ACMP Merger within the Access Midstream segment.
Interest incurred includes transaction-related financing costs of $2 million in 2015 from the ACMP Merger and $9 million in 2014 from the ACMP Acquisition.
Additional Items
Certain items included in Service revenues, Product costs, and Other income (expense) – net below Operating income in the Consolidated Statement of Comprehensive Income (Loss) are as follows:
Service revenues includes $239 million recognized in the fourth quarter of 2015 and $167 million recognized in the fourth quarter of 2014 from minimum volume commitment fees within the Access Midstream segment.
Product costs includes $6 million in 2015 and $27 million in 2014 of inventory adjustments within the NGL & Petchem Services segment.
Other income (expense) – net below Operating income includes $76 million, $33 million, and $19 million for equity AFUDC for 2015, 2014, and 2013, respectively within the Atlantic-Gulf segment. Equity AFUDC increased during 2015 due to the increase in spending on various Transco expansion projects and Constitution.
Other income (expense) – net below Operating income includes a $14 million gain in 2015 resulting from the early retirement of certain debt.
Note 8 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Current:
 
 
 
 
 
State
$
(3
)
 
$
3

 
$
2

Foreign

 
1

 
(22
)
 
(3
)
 
4

 
(20
)
Deferred:
 
 
 
 
 
State
(3
)
 
8

 
15

Foreign
7

 
17

 
35

 
4

 
25

 
50

Provision (benefit) for income taxes
$
1

 
$
29

 
$
30


114





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows:
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
(Millions)
Provision (benefit) at statutory rate
$
(475
)
 
$
459

 
$
402

Increases (decreases) in taxes resulting from:
 
 
 
 
 
Income not subject to U.S. federal tax
475

 
(459
)
 
(402
)
State income taxes
(6
)
 
11

 
17

Foreign operations — net
7

 
18

 
13

Provision (benefit) for income taxes
$
1

 
$
29

 
$
30

The 2015 state deferred benefit includes $7 million related to the impact of a Texas franchise tax rate decrease. The 2015 foreign deferred provision includes $8 million related to the impact of an Alberta provincial tax rate increase.
The 2013 state deferred provision includes $14 million related to the impact of a second-quarter 2013 Texas franchise tax law change.
Income (loss) before income taxes includes $1 million, $72 million, and $61 million of foreign income in 2015, 2014, and 2013, respectively.
Deferred income tax liabilities, primarily attributable to the taxable temporary differences from property, plant, and equipment, were $119 million, $133 million, and $117 million in 2015, 2014, and 2013, respectively.
Cash refunds for income taxes (net of payments) were $4 million and $28 million in 2015 and 2014, respectively. Cash payments for income taxes (net of refunds) in 2013 were $2 million.
As of December 31, 2015, we have no material unrecognized tax benefits.
Tax years after 2011 are subject to examination by the Texas Comptroller. Generally, tax returns for our Canadian entities are open to audit for tax years after 2010. Williams has indemnified us for any adjustments to foreign tax returns filed prior to the Canada Acquisition.
Note 9 – Benefit Plans
Certain of the benefit costs charged to us by our general partners associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below. Employees supporting ACMP were not participants in the pension and other postretirement benefit plans sponsored by Williams during 2014. As a result, there are no 2014 pension and other postretirement benefit costs included in the amounts presented below associated with those employees. During 2014, employees supporting ACMP were eligible for defined contribution plans sponsored by the general partner of ACMP. The cost for the employer matching contributions for the period subsequent to July 1, 2014, is included in the defined contribution amount presented below. Effective January 1, 2015, these employees became Williams employees and eligible for certain employee benefit plans sponsored by Williams and are included in the 2015 amounts presented below.
Defined benefit pension plans
Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan, and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension costs charged to us by Williams for 2015, 2014, and 2013 totaled $43 million, $28 million, and $44 million, respectively. At the total Williams plan level, the pension plans had a projected benefit obligation of $1.5

115





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

billion at December 31, 2015 and 2014. The plans were underfunded by $223 million and $251 million at December 31, 2015 and 2014, respectively.
Postretirement benefits other than pensions
Williams provides certain retiree health care and life insurance benefits for eligible participants. We recognized a net periodic postretirement benefit credited to us by Williams of $12 million, $14 million, and $4 million in 2015, 2014, and 2013, respectively. At the total Williams plan level, the postretirement benefit plans had an accumulated postretirement benefit obligation of $202 million and $233 million at December 31, 2015 and 2014, respectively. The plans were underfunded by $1 million and $25 million at December 31, 2015 and 2014, respectively.
Any differences between the annual expense and amounts currently being recovered in rates by Transco and Northwest Pipeline are recorded as an adjustment to expense and collected or refunded through future rate adjustments.
Defined contribution plans
We were charged compensation expense of $27 million, $25 million, and $16 million in 2015, 2014, and 2013, respectively, for contributions to these plans. The increase in expense in 2015 and 2014 is primarily due to the impact of the ACMP acquisition. (See Note 2 - Acquisitions.)
Note 10 – Inventories

December 31,

2015

2014

(Millions)
Natural gas liquids, olefins, and natural gas in underground storage
$
57


$
150

Materials, supplies, and other
70


81


$
127


$
231


Note 11 – Property, Plant and Equipment
The following table presents nonregulated and regulated Property, plant, and equipment – net as presented on the Consolidated Balance Sheet for the years ended:
 
Estimated
 
Depreciation
 
 
 
 
 
Useful Life (1)
 
Rates (1)
 
December 31,
 
(Years)
 
(%)
 
2015
 
2014
 
 
 
 
 
(Millions)
Nonregulated:
 
 
 
 
 
 
 
Natural gas gathering and processing facilities
5 - 40
 
 
 
$
20,636

 
$
18,717

Construction in progress
Not applicable
 
 
 
740

 
2,115

Other
2 - 45
 
 
 
1,743

 
1,459

Regulated:
 
 
 
 
 
 
 
Natural gas transmission facilities
 
 
1.2 - 6.97
 
12,189

 
10,867

Construction in progress
Not applicable
 
Not applicable
 
941

 
985

Other
5 - 45
 
1.35 - 33.33
 
1,584

 
1,336

Total property, plant, and equipment, at cost
 
 
 
 
$
37,833

 
$
35,479

Accumulated depreciation and amortization
 
 
 
 
(9,233
)
 
(8,157
)
Property, plant, and equipment – net
 
 
 
 
$
28,600

 
$
27,322

____________
(1)
Estimated useful life and depreciation rates are presented as of December 31, 2015. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.

116





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Depreciation and amortization expense for Property, plant, and equipment – net was $1,348 million, $944 million, and $729 million in 2015, 2014, and 2013, respectively.
Regulated Property, plant, and equipment – net includes approximately $706 million and $746 million at December 31, 2015 and 2014, respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.
Asset Retirement Obligations
Our accrued obligations relate to underground storage caverns, offshore platforms and pipelines, fractionation and compression facilities, gas gathering well connections and pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to restore land and remove surface equipment at gas processing, fractionation, and compression facilities, to dismantle offshore platforms and appropriately abandon offshore pipelines, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.
The following table presents the significant changes to our ARO, of which $857 million and $791 million are included in Asset retirement obligations with the remaining portion in Asset retirement obligations under Current liabilities on the Consolidated Balance Sheet at December 31, 2015 and 2014, respectively.
 
December 31,
 
2015
 
2014
 
(Millions)
Beginning balance
$
831

 
$
561

Liabilities incurred
41

 
101

Liabilities settled (1)
(3
)
 
(21
)
Accretion expense
60

 
44

Revisions (2)
(15
)
 
146

Ending balance
$
914

 
$
831

______________
(1)
For 2014, liabilities settled include $7 million related to the abandonment of certain of Transco’s natural gas storage caverns that are associated with a leak in 2010.
(2)
Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining useful life of the assets. The 2015 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets, a decrease in the inflation rate, and increases in the discount rates used in the annual review process. The 2014 revisions primarily reflect an increase in the estimated retirement costs for our offshore pipelines, an increase in the inflation rate, and decreases in the discount rates used in the annual review process.

The funds Transco collects through a portion of its rates to fund its ARO are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) Under its current rate settlement, Transco’s annual funding obligation is approximately $36 million, with installments to be deposited monthly.

117





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Note 12 – Goodwill and Other Intangible Assets
Goodwill
Changes in the carrying amount of goodwill by reportable segment for the periods indicated are as follows:
 
West
 
Access Midstream
 
Northeast G&P
 
Total
 
(Millions)
December 31, 2014
$
45

 
$
429

 
$
646

 
$
1,120

Purchase accounting adjustment
2

 
23

 

 
25

Impairment

 
(452
)
 
(646
)
 
(1,098
)
December 31, 2015
$
47

 
$

 
$

 
$
47

Our goodwill is not subject to amortization, but is evaluated at least annually for impairment or more frequently if impairment indicators are present. We did not identify or recognize any impairments to goodwill in connection with our annual evaluation of goodwill for impairment (performed as of October 1) during the years ended December 31, 2014 and 2013. During 2015, we performed an interim assessment of certain goodwill within the West, Access Midstream, and Northeast G&P segments as of September 30, 2015, but the estimated fair value of the reporting units evaluated exceeded their carrying amounts and thus no impairment charge was recognized. We performed an additional goodwill impairment evaluation as of December 31, 2015, of the goodwill recorded within the West, Access Midstream, and Northeast G&P segments. As a result of this evaluation, we recorded goodwill impairment charges totaling $1.098 billion. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)
Other Intangible Assets
The gross carrying amount and accumulated amortization of Other intangible assets – net of accumulated amortization at December 31 are as follows:
 
2015
 
2014
 
Gross Carrying Amount
 
Accumulated Amortization
 
Gross Carrying Amount
 
Accumulated Amortization
 
(Millions)
Contractual customer relationships
$
10,632

 
$
(663
)
 
$
10,761

 
$
(310
)
Other intangible assets – net of accumulated amortization primarily relate to gas gathering, processing, and fractionation contractual customer relationships recognized in the ACMP and Eagle Ford acquisitions (See Note 2 – Acquisitions) as well as the 2012 acquisitions from Delphi Midstream Partners, LLC (Laser) and Caiman Energy, LLC (Caiman). The decrease in the gross carrying amount of Other intangible assets – net of accumulated amortization during 2015 is primarily related to the $168 million decrease from the purchase price allocation adjustment recorded for the ACMP acquisition in the first quarter of 2015, partially offset by the $32 million increase due to the Eagle Ford acquisition in the second quarter of 2015 (See Note 2 – Acquisitions). The intangible assets are being amortized on a straight-line basis over an initial period of 30 years which represents a portion of the term over which the contractual customer relationships are expected to contribute to our cash flows.
We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the contract periods (as estimated at the time of the respective acquisition), the weighted-average periods prior to the next renewal or extension of the contractual customer relationships associated with the ACMP, Eagle Ford, Laser, and Caiman acquisitions were approximately 17 years, 10 years, 9 years, and 18 years, respectively. Although a significant portion of the expected future cash flows associated with these contracts are dependent on our ability to renew or extend the arrangements beyond the initial contract periods,

118





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investment required.
The amortization expense related to Other intangible assets – net of accumulated amortization was $353 million, $207 million, and $60 million in 2015, 2014, and 2013, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $354 million.

119





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Note 13 – Debt, Banking Arrangements, and Leases
Long-Term Debt
 
 
December 31,
 
 
2015
 
2014
 
 
(Millions)
Unsecured:
 
 
 
 
Transco:
 
 
 
 
6.4% Notes due 2016 (2)
 
$
200

 
$
200

6.05% Notes due 2018
 
250

 
250

7.08% Debentures due 2026
 
8

 
8

7.25% Debentures due 2026
 
200

 
200

5.4% Notes due 2041
 
375

 
375

4.45% Notes due 2042
 
400

 
400

Northwest Pipeline:
 
 
 
 
7% Notes due 2016
 
175

 
175

5.95% Notes due 2017
 
185

 
185

6.05% Notes due 2018
 
250

 
250

7.125% Debentures due 2025
 
85

 
85

Williams Partners L.P.:
 
 
 
 
3.8% Notes due 2015 (1)
 

 
750

7.25% Notes due 2017
 
600

 
600

5.25% Notes due 2020
 
1,500

 
1,500

4.125% Notes due 2020
 
600

 
600

5.875% Notes due 2021
 

 
750

4% Notes due 2021
 
500

 
500

3.6% Notes due 2022
 
1,250

 

3.35% Notes due 2022
 
750

 
750

6.125% Notes due 2022
 
750

 
750

4.875% Notes due 2023
 
1,400

 
1,400

4.5% Notes due 2023
 
600

 
600

4.3% Notes due 2024
 
1,000

 
1,000

4.875% Notes due 2024
 
750

 
750

3.9% Notes due 2025
 
750

 
750

4.0% Notes due 2025
 
750

 

6.3% Notes due 2040

1,250


1,250

5.8% Notes due 2043
 
400

 
400

5.4% Notes due 2044
 
500

 
500

4.9% Notes due 2045
 
500

 
500

5.1% Notes due 2045
 
1,000

 

Term Loan, variable interest rate, due 2018
 
850

 

Credit facility loans
 
1,310

 
640

Capital lease obligations
 
1

 
5

Debt issuance costs
 
(91
)
 
(74
)
Net unamortized debt premium (discount)
 
129

 
207

Long-term debt, including current portion
 
19,177

 
16,256

Long-term debt due within one year
 
(176
)
 
(4
)
Long-term debt
 
$
19,001

 
$
16,252

______________________________________________________
(1)
Presented as long-term debt at December 31, 2014, due to our intent and ability to refinance.
(2)
Presented as long-term debt at December 31, 2015, due to Transco’s intent and ability to refinance.


120





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

The terms of our senior unsecured notes are governed by indentures that contain covenants that, among other things, limit: (1) our ability and the ability of our subsidiaries to create liens securing indebtedness and (2) mergers, consolidations, and sales of assets. The indentures also contain customary events of default, upon which the trustee or the holders of the senior unsecured notes may declare all outstanding senior unsecured notes to be due and payable immediately.
The following table presents aggregate minimum maturities of long-term debt, excluding net unamortized debt premium (discount), debt issuance costs, and capital lease obligations, for each of the next five years:
 
December 31,
2015
 
(Millions)
2016
$
175

2017
785

2018
1,350

2019

2020
2,100

Provisions concerning ACMP long-term debt
Certain long-term debt originally issued by ACMP totaling $2.9 billion has provisions that would require us to make an offer to repurchase such notes at 101 percent of the principle amount should our credit be downgraded by either Moody’s Investor Service or Standard and Poor’s within a period of ninety days following the completion of the proposed ETC Merger.
Issuances and retirements
On January 22, 2016, Transco, issued $1 billion of 7.85 percent senior unsecured notes due 2026 to investors in a private debt placement. Transco intends to use the net proceeds to repay debt and to fund capital expenditures.
In December 2015, we borrowed $850 million on a variable interest rate loan with certain lenders due 2018. At December 31, 2015 the interest rate was 1.85 percent. We used the proceeds for working capital, capital expenditures, and for general partnership purposes.
On April 15, 2015, we paid $783 million, including a redemption premium, to early retire $750 million of 5.875 percent senior notes due 2021 with a carrying value of $797 million.
On March 3, 2015, we completed a public offering of $1.25 billion of 3.6 percent senior unsecured notes due 2022, $750 million of 4 percent senior unsecured notes due 2025, and $1 billion of 5.1 percent senior unsecured notes due 2045. We used the net proceeds to repay amounts outstanding under our commercial paper program and credit facility, to fund capital expenditures, and for general partnership purposes.
We retired $750 million of 3.8 percent senior unsecured notes that matured on February 15, 2015.
On June 27, 2014, Pre-merger WPZ completed a public offering of $750 million of 3.9 percent senior unsecured notes due 2025 and $500 million of 4.9 percent senior unsecured notes due 2045. Pre-merger WPZ used the net proceeds to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes.
On March 4, 2014, Pre-merger WPZ completed a public offering of $1 billion of 4.3 percent senior unsecured notes due 2024 and $500 million of 5.4 percent senior unsecured notes due 2044. Pre-merger WPZ used the net proceeds to repay amounts outstanding under its commercial paper program, to fund capital expenditures, and for general partnership purposes.

121





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Credit Facilities
 
December 31, 2015
 
Available
 
Outstanding
 
(Millions)
Long-term credit facility (1)
$
3,500

 
$
1,310

Letters of credit under certain bilateral bank agreements

 
2

Short-term credit facility
150

 

__________
(1)
In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.
Long-Term Credit Facilities
Prior to our merger both Pre-merger WPZ and ACMP had separate credit facilities that terminated on February 2, 2015.
On February 2, 2015, we along with Transco, Northwest Pipeline, the lenders named therein and an administrative agent entered into the Second Amended & Restated Credit Agreement with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The maturity date of the facility is February 2, 2020. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one year period to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement allows for swing line loans up to an aggregate amount of $150 million, subject to available capacity under the credit facility, and letters of credit commitments of $1.125 billion. Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. On December 18, 2015, we along with Transco, Northwest Pipeline, the lenders named therein and an administrative agent entered into the Amendment No. 1 to Second Amended & Restated Credit Agreement modifying the thresholds specified in the covenant related to the maximum ratio of our debt to EBITDA.
The agreement governing our credit facility contains the following terms and conditions:
Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements, and allow any material change in the nature of its business.
If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies.
Other than swing line loans, each time funds are borrowed, the borrower must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing.  If such borrowing is an alternate base rate borrowing, interest is calculated on the basis of the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus one half of 1 percent and (c) a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus 1 percent, plus, in the case of each of (a), (b) and (c), an applicable margin. If the borrowing is a Eurodollar borrowing, interest is calculated on the basis of LIBOR for the relevant period plus an applicable margin.  Interest on swing line loans is calculated as the sum of the alternate base rate plus an applicable margin.  The borrower is required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings.

122





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Significant financial covenants under the agreement require the ratio of debt to EBITDA, each as defined in the credit facility, be no greater than:
5.75 to 1, for the quarters ending December 31, 2015, March 31, 2016 and June 30, 2016;
5.50 to 1, for the quarters ending September 30, 2016 and December 31, 2016;
5.00 to 1, for the quarter ending March 31, 2017 and each subsequent fiscal quarter, except for the the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the ratio of debt to EBITDA is to be no greater than 5.5 to 1.
The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline. We are in compliance with these financial covenants as measured at December 31, 2015.
As of February 25, 2016, $925 million is outstanding under our long-term credit facility.
Short-Term Credit Facility
On February 3, 2015, we entered into a short-term $1.5 billion credit facility and terminated it on March 3, 2015.
On August 26, 2015, we entered into a credit agreement providing for a $1.0 billion short-term credit facility with a maturity date of August 24, 2016. On December 23, 2015, the capacity of this facility decreased to $150 million in conjunction with entering into the $850 million term loan.
The agreement governing this credit facility contains the following terms and conditions:
This facility becomes available when the aggregate amount of outstanding loans under our long-term credit facility plus outstanding commercial paper borrowings reach a total of $3.5 billion.
Various covenants that limit, among other things, a borrower’s and its respective material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets in certain circumstances, enter into certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements and allow any material change in the nature of its business.
If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments and accelerate the maturity of the loans and exercise other rights and remedies.
Each time funds are borrowed under the credit facility, the borrower may choose from two methods of calculating interest: a fluctuating base rate equal to an alternate base rate plus an applicable margin, or a periodic fixed rate equal to LIBOR plus an applicable margin. The borrower is required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the borrower’s senior unsecured long-term debt ratings.
The significant financial covenant requires the ratio of debt to EBITDA, each as defined in the credit agreement, as of the last day of any fiscal quarter to be no greater than 6.0 to 1.0. We are in compliance with these financial covenants as measured at December 31, 2015.
Commercial Paper Program
On February 2, 2015, we amended and restated the commercial paper program for the ACMP Merger and to allow a maximum outstanding amount of unsecured commercial paper notes of $3 billion. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par

123





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

and bear varying interest rates on a fixed or floating basis. Proceeds from these notes are used for general partnership purposes, including funding capital expenditures, working capital, and partnership distributions.  We classify commercial paper outstanding in Current liabilities in the Consolidated Balance Sheet, as the outstanding notes at December 31, 2015 and December 31, 2014, have maturity dates less than three months from the date of issuance. At December 31, 2015, $499 million of Commercial paper is outstanding at a weighted average interest rate of 0.92 percent. At December 31, 2014, $798 million of Commercial paper is outstanding at a weighted average interest rate of 0.92 percent.

Cash Payments for Interest (Net of Amounts Capitalized)
Cash payments for interest (net of amounts capitalized) were $795 million in 2015, $499 million in 2014, and $366 million in 2013.
Leases-Lessee
The future minimum annual rentals under noncancelable operating leases, are payable as follows:
 
December 31,
2015
 
(Millions)
2016
$
77

2017
63

2018
46

2019
36

2020
32

Thereafter
99

Total
$
353

Total rent expense was $157 million in 2015, $101 million in 2014, and $51 million in 2013 and primarily included in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Comprehensive Income (Loss).
Accounting Standards Issued and Adopted
In April 2015, the FASB issued ASU 2015-03 “Interest - Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03). ASU 2015-03 simplifies the presentation of debt issuance costs by requiring such costs be presented as a deduction from the corresponding debt liability. Subsequently, in August 2015, the FASB issued ASU 2015-15 “Interest-Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements-Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting” (ASU 2015-15). In ASU 2015-15 the FASB stated that the guidance in ASU 2015-03 did not address the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, and entities are permitted to defer and present debt issuance costs related to line-of-credit arrangements as assets. The standards are effective for financial statements issued for interim and annual reporting periods beginning after December 15, 2015, and require retrospective presentation. Early adoption is permitted. We elected to early adopt these standards for the periods presented. Accordingly, $91 million and $74 million of debt issuance costs as of December 31, 2015 and 2014, respectively, are now reflected as a direct reduction of Long-term debt in our Consolidated Balance Sheet. Debt issuance costs related to our credit facilities are presented in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet.

124





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Note 14 – Partners’ Capital
In January 2016, we issued 18,643 common units pursuant to an equity distribution agreement between us and certain banks. The net proceeds of $414 thousand were used for general partnership purposes. We incurred commission fees of $4 thousand associated with these transactions.
In November 2015, we issued 1,790,840 common units pursuant to an equity distribution agreement between us and certain banks. The net proceeds of $59 million were used for general partnership purposes. We incurred commission fees of $592 thousand associated with these transactions.
In 2014, Contributions from The Williams Companies, Inc. – net within the Consolidated Statement of Changes in Equity includes the partners’ equity interests in ACMP as of July 1, 2014, presented within the capital account of the general partner for interests owned by Williams and noncontrolling interests for interests held by the public. Additionally, activity associated with the partners’ equity interests in ACMP during the period under common control until the ACMP Merger date has been presented accordingly within the capital account of the general partner for the interests owned by Williams or noncontrolling interests for interests held by the public. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
Transactions which occurred prior to the ACMP Merger during 2014 and 2013 are summarized below:
In August 2014, Pre-merger WPZ issued 1,080,448 Pre-merger WPZ common units pursuant to an equity distribution agreement between Pre-merger WPZ and certain banks. The net proceeds of $55 million were used for general partnership purposes. Pre-merger WPZ incurred commission fees of $554 thousand associated with these transactions.
In August 2013, Pre-merger WPZ completed an equity issuance of 21,500,000 Pre-merger WPZ common units. Subsequently, the underwriters exercised their option to purchase an additional 3,225,000 Pre-merger WPZ common units. The net proceeds of approximately $1.2 billion were used to repay amounts outstanding under Pre-merger WPZ’s commercial paper program, to fund capital expenditures and for general partnership purposes.
In March 2013, Pre-merger WPZ completed an equity issuance of 14,250,000 Pre-merger WPZ common units, including 3,000,000 Pre-merger WPZ common units sold to Williams in a private placement. Subsequently, the underwriters exercised their option to purchase an additional 1,687,500 Pre-merger WPZ common units. The net proceeds of approximately $760 million were used to repay amounts outstanding under Pre-merger WPZ’s credit facility.
Limited Partners’ Rights
Significant rights of the limited partners include the following:
Right to receive distributions of available cash within 45 days after the end of each quarter.
No limited partner shall have any management control over our business and affairs; the general partner shall conduct, direct and manage our activities.
The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units voting as a single class, including units held by our general partner and its affiliates.

125





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Incentive Distribution Rights
Our general partner is entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below:
 
 
Total Quarterly Distribution per unit
 
Unitholders
 
General
Partner
Minimum Quarterly Distribution
 
$0.3375
 
98%
 
2%
First Target Distribution
 
Up to $0.388125
 
98
 
2
Second Target Distribution
 
Above $0.388125 up to $0.421875
 
85
 
15
Third Target Distribution
 
Above $0.421875 up to $0.50625
 
75
 
25
Thereafter
 
Above $0.50625
 
50
 
50
The table above assumes that the Partnership’s general partner maintains its 2 percent general partner interest, that there are no arrearages on common units, and that the general partner continues to own the IDRs. The maximum distribution sharing percentage of 50 percent includes distributions paid to the general partner on its 2 percent general partner interest and does not include any distributions that the general partner may receive on limited partner units that it owns or may acquire.
In the event of liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and our general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
Issuances of Additional Partnership Securities
Our partnership agreement allows us to issue additional partnership securities for any partnership purpose at any time and from time to time for consideration and on terms and conditions as our general partner determines, all without the approval of any limited partners.
Note 15 – Equity-Based Compensation
Williams’ Plan Information
The Williams Companies, Inc. 2007 Incentive Plan (Plan) provides for Williams common-stock-based awards to both employees and nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved.
Williams bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards.
Operating and maintenance expenses and Selling, general, and administrative expenses include equity-based compensation expense for the years ended December 31, 2015, 2014, and 2013 of $19 million, $14 million and $12 million, respectively.
Williams Partners’ Plan Information
During 2014, certain employees of ACMP’s general partner received equity-based compensation through ACMP’s equity-based compensation program. The fair value of the awards issued was based on the fair market value of the common units on the date of grant. This value is being amortized over the vesting period, which is one to four years from the date of grant. These awards were converted to WPZ equity-based awards in accordance with the terms of the ACMP Merger. No additional grants of restricted common units were awarded through Williams Partners’ equity-based compensation programs in 2015, and no additional grants are expected in the future. Operating and maintenance expenses and Selling, general, and administrative expenses include equity-based compensation expense related to Williams Partners’ equity-based compensation program of $26 million and $11 million for the years ended December 31, 2015 and 2014, respectively. As of December 31, 2015, there was $32 million of unrecognized compensation expense

126





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

attributable to the outstanding awards, which does not include the effect of estimated forfeitures of $4 million. These amounts are expected to be recognized over a weighted average period of 1.8 years.
The following summary reflects nonvested restricted common unit activity for awards issued by Williams Partners and related information for the year ended December 31, 2015:
Restricted Common Units Outstanding
Units
 
Weighted-
Average
Fair Value
 
(Millions)
 
 
Nonvested at December 31, 2014
1.3

 
$
59.35

Adjustment for unit split in ACMP Merger
0.1

 
$

Forfeited
(0.1
)
 
$
58.05

Vested
(0.1
)
 
$
59.28

Nonvested at December 31, 2015
1.2

 
$
55.93

Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, commercial paper, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
 
 
 
 
 
Fair Value Measurements Using
 
 Carrying 
Amount
 
Fair
Value
 
Quoted
Prices In
Active
 Markets for 
Identical
Assets
(Level 1)
 
 Significant 
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
(Millions)
Assets (liabilities) at December 31, 2015:
 
 
 
 
 
 
 
 
 
Measured on a recurring basis:
 
 
 
 
 
 
 
 
 
ARO Trust investments
$
67

 
$
67

 
$
67

 
$

 
$

Energy derivatives assets not designated as hedging instruments
5

 
5

 

 
3

 
2

Energy derivatives liabilities not designated as hedging instruments
(2
)
 
(2
)
 

 

 
(2
)
Additional disclosures:
 
 
 
 
 
 
 
 
 
Notes receivable and other
12

 
12

 
10

 
2

 

Long-term debt, including current portion (1)
(19,176
)
 
(15,988
)
 

 
(15,988
)
 

Assets (liabilities) at December 31, 2014:
 
 
 
 
 
 
 
 
 
Measured on a recurring basis:
 
 
 
 
 
 
 
 
 
ARO Trust investments
$
48

 
$
48

 
$
48

 
$

 
$

Energy derivatives assets not designated as hedging instruments
3

 
3

 
1

 

 
2

Energy derivatives liabilities not designated as hedging instruments
(2
)
 
(2
)
 

 

 
(2
)
Additional disclosures:
 
 
 
 
 
 
 
 
 
Notes receivable and other
5

 
4

 

 
4

 

Long-term debt, including current portion (1)
(16,251
)
 
(16,607
)
 

 
(16,607
)
 

________________
(1)
Excludes capital leases. The carrying value has been reduced by $91 million and $74 million of debt acquisition costs at December 31, 2015 and 2014, respectively. (See Note 13 – Debt, Banking Arrangements, and Leases.)

127





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets and liabilities measured at fair value on a recurring basis
ARO Trust investments:  Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust that is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, is classified as available-for-sale, and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.
Energy derivatives:  Energy derivatives include commodity based exchange-traded contracts and over-the-counter (OTC) contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in Other accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the years ended December 31, 2015 or 2014.
Additional fair value disclosures
Notes receivable and other: The disclosed fair value of our notes receivable is primarily determined by an income approach which considers the underlying contract amounts and our assessment of our ability to recover these amounts. The current portion is reported in Accounts and notes receivable and Other current assets and the noncurrent portion is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet.
Long-term debt:  The disclosed fair value of our long-term debt is determined by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments.
Assets measured at fair value on a nonrecurring basis

We performed an interim assessment of the goodwill associated with our Central Region and Northeast Region reporting units within the Access Midstream segment as of September 30, 2015, and the annual assessment of goodwill associated with our Northeast G&P and West G&P reporting units as of October 1, 2015. No impairment charges were required following these evaluations.
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 as of December 31, 2015, of the goodwill associated with these reporting units.
We estimated 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 ranged from approximately 11 percent to 13 percent across the four reporting units.

128





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

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 Central Region, Northeast Region and Northeast G&P reporting units were determined to be below their respective carrying values. We then calculated the implied fair value of goodwill by performing a hypothetical application of the acquisition method wherein the estimated fair value was allocated to the underlying assets and liabilities of each reporting unit. As a result of these level 3 measurements, we determined that the previously recorded goodwill associated with each reporting unit was fully impaired, resulting in a fourth quarter noncash charge of $1,098 million. For the West G&P reporting unit, the estimated fair value exceeded the carrying value and no impairment was recorded.
 
 
 
 
 
Impairments
 
 
 
 
 
Years Ended December 31,
 
Date of Measurement
 
Fair Value
 
2015
 
2014
 
 
 
(Millions)
Impairment of certain assets (1)
June 30, 2014
 
$
46

 
 
 
$
17

Impairment of certain assets (1)
December 31, 2014
 
32

 
 
 
13

Impairment of certain assets (1)
June 30, 2015
 
17

 
$
20

 
 
Impairment of certain assets (2)
December 31, 2014
 
1

 
 
 
12

Impairment of certain assets (3)
December 31, 2015
 
13

 
94

 
 
Level 3 fair value measurements of certain assets
 
 
 
 
114

 
42

Other impairments (4)
 
 
 
 
31

 
10

Total impairments of certain assets
 
 
 
 
$
145

 
$
52

______________
(1)
Reflects impairment charges for our Northeast G&P segment associated with certain surplus equipment. Certain of these assets were previously presented as held for sale, but are now considered held for use and reported in Property, plant, and equipment – net in the Consolidated Balance Sheet at December 31, 2015. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss).

(2)
Reflects impairment charges for our Access Midstream segment associated with certain surplus equipment considered held for sale and reported in Other current assets in the Consolidated Balance Sheet. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss).

(3)
Reflects an impairment charge within our West segment associated with previously capitalized project development costs for a gas processing plant, the completion of which is now considered remote due to unfavorable impact of low natural gas prices on customer drilling activities. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss). The assessed fair value primarily represents the estimated salvage value of certain equipment measured using a market approach based on our analysis of observable inputs in the principal market and is reported in Property, plant, and equipment – net in the Consolidated Balance Sheet.

(4)
Reflects multiple individually insignificant impairments of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be zero or an insignificant salvage value. These impairment charges are recorded in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Comprehensive Income (Loss).

129





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

 
Date of Measurement
 
Fair Value
 
Impairments
 
 
 
(Millions)
Impairments of equity-method investments (1)
September 30, 2015
 
$
1,203

 
$
461

Impairments of equity-method investments (2)
December 31, 2015
 
4,017

 
890

Other impairment of equity-method investment
December 31, 2015
 
58

 
8

Level 3 fair value measurements of equity-method investments
 
 
 
 
$
1,359

______________
(1)
Reflects other-than-temporary impairment charges related to Access Midstream’s equity-method investments in the Delaware basin gas gathering system and certain of the Appalachia Midstream Investments reflected within Impairment of equity-method investments in the Consolidated Statement of Comprehensive Income (Loss). The historical carrying value of these investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the ACMP Acquisition. We estimated the fair value of these investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized were 11.8 percent and 8.8 percent for the Delaware basin gas gathering system and certain of the Appalachia Midstream Investments, respectively, and reflected our cost of capital as impacted by market conditions, and risks associated with the underlying businesses.
(2)
Reflects other-than-temporary impairment charges related to Access Midstream’s equity-method investments in the Delaware basin gas gathering system, certain of the Appalachia Midstream Investments, and UEOM, as well as an impairment of Northeast G&P’s Laurel Mountain investment, all reflected within Impairment of equity-method investments in the Consolidated Statement of Comprehensive Income (Loss). We estimated the fair value of these investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 10.8 percent to 14.4 percent and reflected further fourth quarter increases in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.
During the first quarter of 2016, we have observed further significant decline in the market value of our publicly traded equity. 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.
Guarantees
We are required by our revolving credit agreements to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.
Concentration of Credit Risk
Cash equivalents
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

130





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Accounts and notes receivable
The following table summarizes concentration of receivables, net of allowances.
 
December 31,
 
2015
 
2014
 
(Millions)
NGLs, natural gas, and related products and services
$
821

 
$
728

Transportation of natural gas and related products
202

 
175

Other
3

 
2

Total
$
1,026

 
$
905

Customers include producers, distribution companies, industrial users, gas marketers and pipelines primarily located in the continental United States and Canada. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. As of December 31, 2015 and 2014, Chesapeake Energy Corporation, and its affiliates, a customer primarily within our Access Midstream segment, accounted for $364 million and $308 million, respectively, of the consolidated Accounts and notes receivable balance. Of this receivable at December 31, 2015, $198 million relates to annual minimum volume commitment fees that were subsequently collected in February 2016.
Revenues
In 2015 and 2014, Chesapeake Energy Corporation, and its affiliates, a customer primarily within our Access Midstream segment, accounted for 18 percent and 9 percent, respectively, of our consolidated revenues.
Note 17 – Contingent Liabilities and Commitments
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2015, we have accrued liabilities totaling $15 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered, and the final cleanup standards mandated by the EPA and other governmental authorities.
The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for one hour nitrogen dioxide emission limits, and new air quality standards impacting storage vessels, pressure valves, and compressors. On October 1, 2015, the EPA issued its new rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a new standard of 70 parts per billion. We are monitoring the rule’s implementation and evaluating potential impacts to our operations. For these and other new regulations, we are unable to estimate the costs of asset additions or modifications necessary to comply due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

131





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At December 31, 2015, we have accrued liabilities of $8 million for these costs. We expect that these costs will be recoverable through rates.
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2015, we have accrued liabilities totaling $7 million for these costs.
Geismar Incident
As a result of the previously discussed Geismar Incident, there were two fatalities and numerous individuals (including employees and contractors) reported injuries, which varied from minor to serious. We are addressing the following matters in connection with the Geismar Incident.
On October 21, 2013, the EPA issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through June 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. On June 16, 2014, we received a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. The EPA could issue penalties pertaining to final determinations.
Multiple lawsuits, including class actions for alleged offsite impacts, property damage, customer claims, and personal injury, have been filed against us. To date, we have settled certain of the personal injury claims for an aggregate immaterial amount that we have recovered from our insurers. The trial for certain plaintiffs claiming personal injury, that was set to begin on June 15, 2015, in Iberville Parish, Louisiana, has been postponed to September 6, 2016. We believe it is probable that additional losses will be incurred on some lawsuits, while for others we believe it is only reasonably possible that losses will be incurred. However, due to ongoing litigation involving defenses to liability, the number of individual plaintiffs, limited information as to the nature and extent of all plaintiffs’ damages, and the ultimate outcome of all appeals, we are unable to reliably estimate any such losses at this time. We believe that it is probable that any ultimate losses incurred will be covered by our general liability insurance policy, which has an aggregate limit of $610 million applicable to this event and retention (deductible) of $2 million per occurrence.
Royalty Matters
Certain of our customers, including one major customer, have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases in Texas, Pennsylvania, and Ohio based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We have also received subpoenas from the United States Department of Justice and the Pennsylvania Attorney General requesting documents relating to the agreements between us and our major customer and calculations of the major customer’s royalty payments. On December 9, 2015, the Pennsylvania Attorney General filed a civil suit against one of our major customers and us alleging breaches of the Pennsylvania Unfair Trade Practices and Consumer Protection Law, and on February 8, 2016, the Pennsylvania Attorney General filed an amended complaint in such civil suit, which omitted us as a party. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. Due to the preliminary status of the cases, we are unable to estimate a range of liability at this time.
Stockholder Litigation
In July 2015, a purported stockholder of Williams filed a putative class and derivative action on behalf of Williams in the Court of Chancery of the State of Delaware. The action names as defendants certain members of Williams’ Board

132





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

of Directors (Individual Defendants), as well as us, and names Williams as a nominal defendant. On December 4, 2015, the plaintiff filed an amended complaint for such action, and we are no longer a party to such lawsuit.
Other
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.
Summary
We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties.
Commitments
Commitments for construction and acquisition of property, plant, and equipment are approximately $617 million at December 31, 2015.
Note 18 – Segment Disclosures
Our reportable segments are Access Midstream, Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
Performance Measurement
Prior to the first quarter of 2015, we evaluated segment operating performance based upon Segment profit (loss) from operations. Beginning in the first quarter of 2015, we evaluate segment operating performance based upon Modified EBITDA (earnings before interest, taxes, depreciation, and amortization). This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Prior period segment disclosures have been recast to reflect this change. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business.
We define Modified EBITDA as follows:
Net income (loss) before:
Provision (benefit) for income taxes;
Interest incurred, net of interest capitalized;
Equity earnings (losses);
Impairment of equity-method investments;
Other investing income (loss) net;
Impairment of goodwill;
Depreciation and amortization expenses;
Accretion expense associated with asset retirement obligations for nonregulated operations.
This measure is further adjusted to include our proportionate share (based on ownership interest) of Modified EBITDA from our equity-method investments calculated consistently with the definition described above.

133





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

The following geographic area data includes Revenues from external customers based on product shipment origin and Long-lived assets based upon physical location.
 
 
 
United States
 
Canada
 
Total
 
 
 
(Millions)
Revenues from external customers:
 
 
 
 
 
 
 
2015
 
$
7,228

 
$
103

 
$
7,331

 
2014
 
7,212

 
197

 
7,409

 
2013
 
6,685

 
150

 
6,835

 
 
 
 
 
 
 
 
Long-lived assets:
 
 
 
 
 
 
 
2015
 
$
37,586

 
$
1,030

 
$
38,616

 
2014
 
37,798

 
1,095

 
38,893

 
2013
 
18,776

 
1,137

 
19,913

Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets.

134





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Comprehensive Income (Loss) and Other financial information.

Access Midstream
 
Northeast
G&P

Atlantic-
Gulf

West

NGL &
Petchem
Services

Eliminations 

Total

(Millions)
2015
Segment revenues:
 
 











Service revenues
 
 











External
$
1,523

 
$
541

 
$
1,877

 
$
1,055

 
$
139

 
$

 
$
5,135

Internal

 
7

 
4

 

 

 
(11
)
 

Total service revenues
1,523

 
548

 
1,881

 
1,055

 
139

 
(11
)
 
5,135

Product sales
 
 
 
 
 
 
 
 
 
 
 
 
 
External

 
109

 
287

 
36

 
1,764

 

 
2,196

Internal

 
18

 
176

 
221

 
157

 
(572
)
 

Total product sales

 
127

 
463

 
257

 
1,921

 
(572
)
 
2,196

Total revenues
$
1,523

 
$
675

 
$
2,344

 
$
1,312

 
$
2,060

 
$
(583
)
 
$
7,331

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other financial information:
 
 
 
 
 
 
 
 
 
 
 
 
 
Proportional Modified EBITDA of equity-method investments
$
338

 
$
62

 
$
257

 
$

 
$
42

 
 
 
$
699

2014
 
 
 
 
Segment revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
Service revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
External
$
765

 
$
450

 
$
1,497

 
$
1,050

 
$
126

 
$

 
$
3,888

Internal

 
1

 
4

 

 

 
(5
)
 

Total service revenues
765

 
451

 
1,501

 
1,050

 
126

 
(5
)
 
3,888

Product sales
 
 
 
 
 
 
 
 
 
 
 
 
 
External

 
225

 
499

 
70

 
2,727

 

 
3,521

Internal

 
5

 
354

 
476

 
259

 
(1,094
)
 

Total product sales

 
230

 
853

 
546

 
2,986

 
(1,094
)
 
3,521

Total revenues
$
765

 
$
681

 
$
2,354

 
$
1,596

 
$
3,112

 
$
(1,099
)
 
$
7,409

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other financial information:
 
 
 
 
 
 
 
 
 
 
 
 
 
Proportional Modified EBITDA of equity-method investments
$
178


$
52


$
151


$


$
50

 
 
 
$
431

2013
 
 
 
 
 
 
 
 
 
 
 
 
 
Segment revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
Service revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
External
$

 
$
335

 
$
1,414

 
$
1,053

 
$
112

 
$

 
$
2,914

Internal

 

 
10

 
1

 

 
(11
)
 

Total service revenues

 
335

 
1,424

 
1,054

 
112

 
(11
)
 
2,914

Product sales
 
 
 
 
 
 
 
 
 
 
 
 
 
External

 
166

 
830

 
64

 
2,861

 

 
3,921

Internal

 

 
95

 
708

 
294

 
(1,097
)
 

Total product sales

 
166

 
925

 
772

 
3,155

 
(1,097
)
 
3,921

Total revenues
$

 
$
501

 
$
2,349

 
$
1,826

 
$
3,267

 
$
(1,108
)
 
$
6,835

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other financial information:
 
 
 
 
 
 
 
 
 
 
 
 
 
Proportional Modified EBITDA of equity-method investments
$


$
15


$
144


$


$
50

 
 
 
$
209


135





Williams Partners L.P.
Notes to Consolidated Financial Statements – (Continued)
 

The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Comprehensive Income (Loss),
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
 
 
 
 
(Millions)
Modified EBITDA by segment:
 
 
 
 
 
Access Midstream
$
1,279

 
$
642

 
$

Northeast G&P
314

 
395

 
114

Atlantic-Gulf
1,523

 
1,065

 
1,013

West
557

 
823

 
924

NGL & Petchem Services
321

 
324

 
395

Other
9

 
(5
)
 
1

 
4,003

 
3,244

 
2,447

Accretion expense associated with asset retirement obligations for nonregulated operations
(28
)
 
(17
)
 
(14
)
Depreciation and amortization expenses
(1,702
)
 
(1,151
)
 
(791
)
Impairment of goodwill
(1,098
)
 

 

Equity earnings (losses)
335

 
228

 
104

Impairment of equity-method investments
(1,359
)
 

 

Other investing income (loss) – net
2

 
2

 
(1
)
Proportional Modified EBITDA of equity-method investments
(699
)
 
(431
)
 
(209
)
Interest expense
(811
)
 
(562
)
 
(387
)
(Provision) benefit for income taxes
(1
)
 
(29
)
 
(30
)
Net income (loss)
$
(1,358
)
 
$
1,284

 
$
1,119

The following table reflects Total assets, Investments, and Additions to long-lived assets by reportable segments:
 
Total Assets at December 31,
 
Investments at December 31,
 
Additions to Long-Lived Assets at December 31,
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
2013
 
(Millions)
Access Midstream (1)
$
21,050

 
$
22,470

 
$
5,039

 
$
6,004

 
$
556

 
$
16,964

 
$

Northeast G&P
6,669

 
7,314

 
834

 
891

 
367

 
1,079

 
1,376

Atlantic-Gulf
12,171

 
11,114

 
959

 
985

 
1,573

 
1,593

 
1,072

West
5,035

 
5,174

 

 

 
225

 
168

 
210

NGL & Petchem Services
3,306

 
3,510

 
504

 
519

 
236

 
601

 
746

Other corporate assets
350

 
501

 

 

 
3

 
8

 
5

Eliminations (2)
(711
)
 
(835
)
 

 

 

 

 

Total
$
47,870

 
$
49,248

 
$
7,336

 
$
8,399

 
$
2,960

 
$
20,413

 
$
3,409

 
(1)
2014 Additions to long-lived assets within our Access Midstream segment primarily includes the acquisition-date fair value of long-lived assets from the ACMP Acquisition (Note 2 – Acquisitions).
(2)
Eliminations primarily relate to the intercompany accounts receivable generated by our cash management program.


136





Williams Partners L.P.
Quarterly Financial Data
(Unaudited)



Summarized quarterly financial data are as follows:     

 
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 
 
(Millions, except per-unit amounts)
2015
 
 
 
 
 
 
 
 
Revenues
 
$
1,711

 
$
1,830

 
$
1,792

 
$
1,998

Product costs
 
463

 
494

 
426

 
396

Net income (loss)
 
112

 
332

 
(167
)
 
(1,635
)
Net income (loss) attributable to controlling interests
 
89

 
300

 
(194
)
 
(1,644
)
Net income (loss) allocated to common units for calculation of earnings per common unit (1)
 
(172
)
 
83

 
(190
)
 
(1,577
)
Basic and diluted net income (loss) per common unit (2)
 
(.34
)
 
.14

 
(.32
)
 
(2.68
)
2014
 
 
 
 
 
 
 
 
Revenues
 
$
1,693

 
$
1,616

 
$
2,008

 
$
2,092

Product costs
 
769

 
724

 
807

 
716

Net income (loss)
 
352

 
223

 
247

 
462

Net income (loss) attributable to controlling interests
 
352

 
221

 
233

 
382

Net income (loss) allocated to common units for calculation of earnings per common unit
 
158

 
47

 
29

 
$
125

Basic and diluted net income (loss) per common unit
 
.44

 
.13

 
.08

 
$
.35

________________
(1)
The sum of Net income (loss) allocated to common units for calculation of earnings per common unit for the four quarters may not equal the total for the year due to timing of unit issuances.
(2)
The sum of Net income (loss) per common unit for the four quarters may not equal the total for the year due to changes in the average number of common units outstanding and rounding.
2015
Net income (loss) for fourth-quarter 2015 includes:
$239 million in revenue associated with minimum volume commitment fees at Access Midstream (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements);
$10 million impairment loss on certain assets at Access Midstream (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk);
$97 million impairment loss on certain assets at West (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk);
$898 million impairment loss on certain equity-method investments (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk);
$1,098 million impairment of goodwill (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).
Net income (loss) for third-quarter 2015 includes:
$16 million equity losses related to our share of underlying property impairments at certain equity-method investments at Access Midstream (see Note 6 – Investing Activities);

137





Williams Partners L.P.
Quarterly Financial Data – (Continued)
(Unaudited)


$461 million impairment loss on certain equity-method investments (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).
Net income (loss) for second-quarter 2015 includes:
$126 million gain associated with insurance recoveries related to the Geismar Incident at NGL & Petchem Services (see Note 7 – Other Income and Expenses);
$14 million gain associated with the early retirement of certain debt (see Note 7 – Other Income and Expenses);
$14 million of ACMP Merger and transition-related expenses at Access Midstream (see Note 7 – Other Income and Expenses);
$21 million impairment loss on certain assets at Northeast G&P (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).
Net income (loss) for first-quarter 2015 includes $32 million of ACMP Merger and transition-related expenses primarily at Access Midstream (see Note 7 – Other Income and Expenses).
2014
Net income (loss) for fourth-quarter 2014 includes:
$167 million in revenue associated with minimum volume commitment fees at Access Midstream (see Note 7 – Other Income and Expenses);
$154 million gain related to a contingency settlement at Northeast G&P (see Note 7 – Other Income and Expenses);
$71 million gain associated with insurance recoveries related to the Geismar Incident at NGL & Petchem Services (see Note 7 – Other Income and Expenses);
$10 million impairment loss on certain assets at Atlantic-Gulf (see Note 7 – Other Income and Expenses);
$12 million impairment loss on certain assets held for sale at Access Midstream (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk);
$13 million impairment loss on certain assets at Northeast G&P (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk);
$17 million unfavorable inventory adjustment related to a decrease in prices at NGL & Petchem Services (see Note 7 – Other Income and Expenses);
$31 million of ACMP Acquisition, merger, and transition-related expenses primarily at Access Midstream (see Note 2 – Acquisitions and Note 7 – Other Income and Expenses).
Net income (loss) for third-quarter 2014 includes:
$12 million net gain related to a partial acreage dedication release at Northeast G&P (see Note 7 – Other Income and Expenses);
$13 million in ACMP Acquisition expenses at Access Midstream, in addition to $11 million of merger and transition-related expenses (see Note 2 – Acquisitions and Note 7 – Other Income and Expenses).

138





Williams Partners L.P.
Quarterly Financial Data – (Continued)
(Unaudited)


Net income (loss) for second-quarter 2014 includes:
$50 million gain associated with insurance recoveries related to the Geismar Incident at NGL & Petchem Services (see Note 7 – Other Income and Expenses);
$11 million of ACMP Acquisition-related expenses, including $9 million of financing expenses (see Note 2 – Acquisitions and Note 7 – Other Income and Expenses);
$17 million impairment loss on certain assets at Northeast G&P (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).
Net income (loss) for first-quarter 2014 includes a gain of $125 million associated with insurance recoveries related to the Geismar Incident at NGL & Petchem Services (see Note 7 – Other Income and Expenses).

139



Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
Our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act) (Disclosure Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Williams Partners L.P. have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes during the fourth quarter of 2015 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.
Management’s Annual Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a - 15(f) and 15d - 15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

140



Under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2015, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment we concluded that, as of December 31, 2015, our internal control over financial reporting was effective.
Ernst & Young LLP, our independent registered public accounting firm, has audited our internal control over financial reporting, as stated in their report which is included in this Annual Report on Form 10-K.




























141



Report of Independent Registered Public Accounting Firm
On Internal Control Over Financial Reporting

The Board of Directors of WPZ GP LLC,
General Partner of Williams Partners L.P.
and the Limited Partners of Williams Partners L.P.

We have audited Williams Partners L.P.’s (the “Partnership”) internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Williams Partners L.P.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Williams Partners L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Williams Partners L.P. as of December 31, 2015 and 2014, and the related consolidated statements of comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2015, and our report dated February 26, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 26, 2016



142




Item 9B. Other Information
None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance
As a limited partnership, we have no directors or officers. Instead, our general partner, Williams Partners GP LLC, manages our operations and activities. Our general partner is not elected by our unitholders and is not subject to re-election on a regular basis in the future. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner’s directors are appointed by Williams, the corporate parent of our general partner. Accordingly, we do not have a procedure by which our unitholders may recommend nominees to our general partner’s Board of Directors.
All of the senior officers of our general partner are also senior officers of Williams.
The following table shows information for the directors and executive officers of our general partner. 
Name
 
Age
 
Position with Williams Partners GP LLC
Alan S. Armstrong
 
53
 
Chairman of the Board and Chief Executive Officer
Donald R. Chappel
 
64
 
Chief Financial Officer and Director
Robert S. Purgason
 
59
 
Senior Vice President - Central and Director
Rory L. Miller
 
55
 
Senior Vice President - Atlantic-Gulf and Director
James E. Scheel
 
51
 
Senior Vice President - Northeast G&P and Director
H. Brent Austin
 
61
 
Director and Member of Audit and Conflicts Committees
Alice M. Peterson
 
63
 
Director and Member of Audit and Conflicts Committees
Philip L. Fredrickson
 
59
 
Director and Member of Audit and Conflicts Committees
Frank E. Billings
 
53
 
Senior Vice President - Corporate Strategic Development and Director
Walter Bennett
 
46
 
Senior Vice President - West
John R. Dearborn
 
58
 
Senior Vice President - NGL & Petchem Services
Fred E. Pace
 
54
 
Senior Vice President - E&C
Brian L. Perilloux
 
54
 
Senior Vice President - Operational Excellence
John D. Seldenrust
 
51
 
Senior Vice President - E&C
Sarah C. Miller
 
44
 
Senior Vice President, General Counsel, and Secretary
Ted T. Timmermans
 
59
 
Vice President, Controller, and Chief Accounting Officer
Officers serve at the discretion of the Board of Directors of our general partner. There are no family relationships among any of the directors or executive officers of our general partner. The directors of our general partner are appointed for one-year terms. In addition to independence and financial literacy for members of our general partner’s Board of Directors who serve on the Audit Committee and Conflicts Committee, our general partner considers the following qualifications relevant to service on its Board of Directors in the context of our business and structure: 
Industry Experience in the oil, natural gas, and petrochemicals business.
Engineering and Construction Experience.
Financial and Accounting Experience.

143



Corporate Governance Experience.
Securities and Capital Markets Experience.
Executive Leadership Experience.
Public Policy and Government Experience.
Strategy Development and Risk Management Experience.
Operating Experience.
Knowledge of the marketplace and political and regulatory environments relevant to the energy sector in the locations where we operate currently or plan to in the future (Marketplace Knowledge).
Certain information about each of our general partner’s directors and executive officers is set forth below, including qualifications relevant to service on our general partner’s Board of Directors.
Alan S. Armstrong has served as a director of our general partner since 2012, as Chief Executive Officer of our general partner since December 31, 2014, and as Chairman of the Board of Directors of our general partner since February 2, 2015. Mr. Armstrong has served as the Chief Executive Officer, President, and a director of Williams since 2011. Mr. Armstrong served as a director of the general partner of Pre-merger WPZ (the Pre-merger WPZ Board) from 2005 until the ACMP Merger on February 2, 2015, as the Chairman of the Pre-merger WPZ Board and the Chief Executive Officer of the general partner of Pre-merger WPZ (the Pre-merger WPZ General Partner) from 2011 until the ACMP Merger. From 2010 to 2011, Mr. Armstrong served as Senior Vice President - Midstream of the Pre-merger WPZ General Partner. From 2005 until 2010, Mr. Armstrong served as the Chief Operating Officer of the Pre-merger WPZ General Partner. From 2002 to 2011, Mr. Armstrong served as Senior Vice President - Midstream of Williams and acted as President of Williams’ midstream business. From 1999 to 2002, Mr. Armstrong was Vice President, Gathering and Processing in Williams’ midstream business and from 1998 to 1999 was Vice President, Commercial Development, in Williams’ midstream business. Mr. Armstrong has also served as a director of BOK Financial Corporation (a financial services company) since 2013.
As our current Chief Executive Officer and as acquired during his roles of increasing responsibilities in our midstream business, Mr. Armstrong’s qualifications include industry, engineering and construction, financial and accounting, corporate governance, securities and capital markets, executive leadership, strategy development and risk management, operating experience, and marketplace knowledge.
Donald R. Chappel has served as a director of our general partner since 2012 and as Chief Financial Officer of our general partner since December 31, 2014. Mr. Chappel has served as Senior Vice President and Chief Financial Officer of Williams since 2003. Mr. Chappel served as the Chief Financial Officer and a director of the Pre-merger WPZ General Partner from 2005 until the ACMP Merger. Mr. Chappel served as Chief Financial Officer and a director of the general partner of Williams Pipeline Partners L.P. (WMZ) (a limited partnership formed by Williams to own and operate natural gas transportation and storage assets) from 2008 until WMZ merged with Pre-merger WPZ in 2010. Mr. Chappel has served as a member of the Management Committee of Northwest Pipeline since 2007. Mr. Chappel also serves as a director of SUPERVALU Inc. (a grocery and pharmacy company).
Mr. Chappel’s qualifications include marketplace knowledge and industry, financial and accounting, corporate governance, securities and capital markets, executive leadership, and strategy development and risk management experience.
Robert S. Purgason has served as a director of our general partner since 2012 and as Senior Vice President - Central of our general partner since the ACMP Merger. Mr. Purgason has served as Senior Vice President-Central of Williams since January 1, 2015. Mr. Purgason served as Chief Operating Officer of our general partner from 2010 until the ACMP Merger. Prior to joining our general partner, Mr. Purgason spent five years at Crosstex Energy L.P. and was promoted to Senior Vice President - Chief Operating Officer in 2006. Prior to Crosstex, Mr. Purgason spent 19 years with Williams

144



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.
Mr. Purgason’s qualifications include marketplace knowledge and industry, engineering and construction, financial and accounting, corporate governance, securities and capital markets, executive leadership, public policy and government, strategy development and risk management, and operating experience.
Rory L. Miller has served as a director of our general partner and as Senior Vice-President - Atlantic-Gulf of our general partner since the ACMP Merger. Mr. Miller has served as Senior Vice President - Atlantic Gulf of Williams since 2013 and served in that role for the Pre-merger WPZ General Partner from 2011 until the ACMP Merger. From 2011 until 2013, Mr. Miller was Senior Vice President - Midstream of Williams and the Pre-merger WPZ General Partner, acting as President of Williams’ midstream business. Mr. Miller was a Vice President of Williams’ midstream business from 2004 until 2011. Mr. Miller has served as a member of the Management Committee of Transco since 2013.
Mr. Miller’s qualifications include marketplace knowledge and industry, engineering and construction, executive leadership, strategy development and risk management, and operating experience.
James E. Scheel has served as a director of our general partner and as Senior Vice President - Northeast G&P since the ACMP Merger. Mr. Scheel has served as Senior Vice President - Northeast G&P of Williams since January 2014 and served in that role for the Pre-merger WPZ General Partner from January 2014 until the ACMP Merger. Mr. Scheel served as a director of the Pre-merger WPZ General Partner from 2012 until the ACMP Merger. Mr. Scheel served as a director of the Pre-merger ACMP General Partner from 2012 to February 2014. Mr. Scheel served as Senior Vice President - Corporate Strategic Development of Williams and the Pre-merger WPZ General Partner from 2012 to January 2014. Mr. Scheel served as Vice President of Business Development of Williams’ midstream business from 2011 until 2012. Mr. Scheel joined Williams in 1988 and has served in leadership roles in business strategic development, engineering and operations, the NGL business, and international operations.
Mr. Scheel’s qualifications include marketplace knowledge and industry, engineering and construction, executive leadership, strategy development and risk management, and operating experience.
H. Brent Austin has served as a director of our general partner since the ACMP Merger. Mr. Austin served as a director of the Pre-merger WPZ General Partner from 2010 until the ACMP Merger. Mr. Austin has been Managing Director and Chief Investment Officer of Alsamora L.P., a Houston-based private limited partnership with real estate and diversified equity investments, since 2003. Mr. Austin served as a director of the general partner of WMZ from 2008 until WMZ merged with Pre-merger WPZ in 2010. From 2002 to 2003, Mr. Austin was President and Chief Operating Officer of El Paso Corporation, an owner and operator of natural gas transportation pipelines, storage, and other midstream assets, where he managed all nonregulated operations as well as all financial functions.
Mr. Austin’s qualifications include marketplace knowledge and industry, financial and accounting, corporate governance, securities and capital markets, executive leadership, public policy and government, strategy development and risk management, and operating experience.
Alice M. Peterson has served as a director of our general partner since the ACMP Merger. Ms. Peterson served as a director of the Pre-merger WPZ General Partner from 2005 until the ACMP Merger. Ms. Peterson is currently President of Loretto Group, a consultancy focused on sustainably profitable business growth. From 2012 through 2015, she served as Chief Operating Officer of PPL Group and Big Shoulders Capital, both private equity firms with common ownership. Ms. Peterson served as a director of RIM Finance, LLC, a wholly owned subsidiary of Research in Motion, Ltd., the maker of the Blackberry™ handheld device, from 2000 to 2013. From 2009 to 2010, Ms. Peterson served as the Chief Ethics Officer of SAI Global, a provider of compliance and ethics services, and was a special advisor to SAI Global until 2012. Ms. Peterson served as a director of Patina Solutions, which provides professionals on a flexible basis to help companies achieve their business objectives from 2012 to 2013. Ms. Peterson founded and served as the president of Syrus Global, a provider of ethics, compliance, and reputation management solutions from 2002 to 2009, when it was acquired by SAI Global. From 2000 to 2001, Ms. Peterson served as President and General Manager of RIM

145



Finance, LLC. From 1998 to 2000, Ms. Peterson served as Vice President of Sears Online and from 1993 to 1998, as Vice President and Treasurer of Sears, Roebuck and Co. Ms. Peterson previously served as a director of Navistar Financial Corporation, a wholly owned subsidiary of Navistar International (a manufacturer of commercial and military trucks, diesel engines and parts), Hanesbrands Inc. (an apparel company), TBC Corporation (a marketer of private branded replacement tires), and Fleming Companies (a supplier of consumer package goods).
Ms. Peterson’s qualifications include industry, financial and accounting, corporate governance, securities and capital markets, executive leadership, strategy development and risk management, and operating experience.

Philip L. Frederickson has served as a director of our general partner since 2010. Mr. Frederickson retired from ConocoPhillips (then an international, integrated oil company) after 29 years of service. At the time of his retirement, he was Executive Vice President Planning, Strategy and Corporate Affairs. He also served as a board member for Chevron Phillips Chemical (a chemical producer) and DCP Midstream (a natural gas processor and marketer). Mr. Frederickson joined Conoco in 1978 and held several senior positions in the United States and Europe, including General Manager, Strategy and Business Development; General Manager, Refining and Marketing Europe; Managing Director, Conoco Ireland; General Manager, Refining and Marketing; General Manager, Strategy and Portfolio Management, Upstream; and Vice President, Business Development. Mr. Frederickson was Senior Vice President of Corporate Strategy and Business Development for Conoco Inc. from 2001 to 2002. Following the announcement of the merger of Conoco and Phillips in 2001, Mr. Frederickson was named integration lead to coordinate the merger transition and in 2002 was made Executive Vice President, Commercial, of ConocoPhillips. Mr. Frederickson serves as a board member for Entergy Corporation, and as a director emeritus for the Yellowstone Park Foundation. Mr. Fredrickson previously served as a director of Sunoco Logistics Partners L.P. and Rosetta Resources Inc.
Mr. Fredrickson’s qualifications include marketplace knowledge and industry, engineering and construction, financial and accounting, corporate governance, securities and capital markets, public policy and government, strategy and risk management, mergers and acquisitions, and operating experience.
Frank E. Billings has served as a director of our general partner since the ACMP Merger and as Senior Vice President - Corporate Strategic Development of Williams and our general partner since January 2014. From January 2013 to January 2014, he served as Senior Vice President - Northeast G&P of Williams and our general partner. Mr. Billings served as a Vice President of Williams’ midstream business from 2011 until 2013 and as Vice President, Business Development of Williams from 2010 to 2011. He served as President of Cumberland Plateau Pipeline Company (a privately held company developing an ethane pipeline to serve the Marcellus shale area) from 2009 until 2010. From 2008 to 2009, Mr. Billings served as Senior Vice President of Commercial for Crosstex Energy, Inc. and Crosstex Energy L.P. (an independent midstream energy services master limited partnership and its parent corporation). In 1988, Mr. Billings joined MAPCO Inc., which merged with a Williams subsidiary in 1998, serving in various management roles, including in 2008 as a Vice President in the midstream business.
Mr. Billings’ qualifications include industry, executive leadership, risk management, and operating experience.
Walter J. Bennett has served as Senior Vice President - West of our general partner since December 2013. Mr. Bennett has served as Senior Vice President-West of Williams since January 1, 2015 and served in that same role for the Pre-merger WPZ General Partner until the ACMP Merger. He most recently was Vice President - Western Operations for our general partner. Prior, he was Chief Operating Officer of Chesapeake Midstream Development. Before joining our general partner, Mr. Bennett 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.
John R. Dearborn has served as Senior Vice President - NGL & Petchem Services of our general partner since the ACMP Merger. Mr. Dearborn served as Senior Vice President - NGL & Petchem Services of Williams since 2013 and also served in that role for the Pre-merger WPZ General Partner from 2013 until the ACMP Merger. Mr. Dearborn served as a senior leader for Saudi Basic Industries Corporation, a petrochemical company, from 2011 to 2013. From 2001 to 2011, Mr. Dearborn served in a variety of leadership positions with The Dow Chemical Company (Dow). Mr. Dearborn also worked for Union Carbide Corporation (prior to its merger with Dow) from 1981 to 2001 where he served in several leadership roles.

146



Fred E. Pace has served as Senior Vice President - E&C (Engineering and Construction) of our general partner since the ACMP Merger. Mr. Pace has served as Senior Vice President - E&C of Williams since 2013 and also served in that role for the Pre-merger WPZ General Partner from 2013 until the ACMP Merger. From 2011 until 2013, Mr. Pace served Williams in project engineering and development roles, including service as Vice President, Engineering and Construction for Williams’ 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.
Brian L. Perilloux has served as Senior Vice President – Operational Excellence of our general partner since the ACMP Merger. Mr. Perilloux has served as Senior Vice President - Operational Excellence of Williams since 2013 and served in that role for the Pre-merger WPZ General Partner from 2013 until the ACMP Merger. Mr. Perilloux served as a Vice President of Williams’ midstream business from 2011 until 2013. Mr. Perilloux served in various roles in Williams’ midstream business, including engineering and construction roles from 2007 to 2011. Prior to joining Williams, Mr. Perilloux was an officer of a private international engineering and construction company.
Sarah C. Miller has served as Senior Vice President, General Counsel, and Secretary of our general partner since June 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.
Ted T. Timmermans has served as Vice President, Controller, and Chief Accounting Officer of our general partner since the ACMP Merger. Mr. Timmermans has served as Vice President, Controller, and Chief Accounting Officer of Williams since 2005 and served in those roles for the Pre-merger WPZ General Partner from 2005 until the ACMP Merger. Mr. Timmermans served as an Assistant Controller of Williams from 1998 to 2005. Mr. Timmermans served as Chief Accounting Officer of the general partner of WMZ from 2008 until WMZ merged with Pre-merger WPZ in 2010.
John D. Seldenrust serves as Senior Vice President - E&C (Engineering and Construction) for Williams. He is responsible for delivering best-in-class engineering, design, and construction management across all of Williams’ businesses. Mr. Seldenrust’s experience in the industry spans more than 25 years. Before taking his current role in January 2016, Mr. Seldenrust served as Senior Vice President - Eastern Operations for Williams and Access Midstream (formerly Chesapeake Midstream). Prior to joining Chesapeake, Mr. Seldenrust held Reservoir, Production, and Facilities Engineering positions with ARCO Oil & Gas, Vastar Resources, and BP America. Mr. Seldenrust holds a degree in Chemical Engineering from Texas A&M University, a Master of Divinity from Colorado International University, and serves on the boards of Construction Industry Institute and TeenPact Leadership Schools.
Governance
Our general partner adopted governance guidelines that address, among other areas, director independence, policies on meeting attendance and preparation, executive sessions of nonmanagement directors and communications with nonmanagement directors.
Director Independence
Because we are a limited partnership, the NYSE does not require our general partner’s Board of Directors to be composed of a majority of directors who meet the criteria for independence required by the NYSE or to maintain nominating/corporate governance and compensation committees composed entirely of independent directors.
Our general partner’s Board of Directors has adopted governance guidelines which require at least three members of our general partner’s Board of Directors to be independent directors as defined by the rules of the NYSE and have no material relationship with us or our general partner. Our general partner’s Board of Directors at least annually reviews

147



the independence of its members expected to be independent and affirmatively makes a determination that each director meets these independence standards.
Our general partner’s Board of Directors affirmatively determined that each of Ms. Peterson, and Messrs. Austin and Fredrickson is an “independent director” under the current listing standards of the NYSE and our director independence standards. The Board also determined that David A. Daberko, who resigned from the Board on December 3, 2015, was an “Independent director” under the foregoing NYSE and partnership standards. In so doing, the Board of Directors determined that each of these individuals met the “bright line” independence standards of the NYSE. In addition, there were no transactions or relationships between each director and any member of his or her immediate family on one hand, and us or any affiliate of us on the other, that were identified and considered by the Board of Directors. Accordingly, the Board of Directors of our general partner affirmatively determined that all of the directors mentioned above are independent. Because Messrs. Armstrong, Chappel, Purgason, Miller, and Scheel, are employees, officers and/or directors of Williams, they are not independent under these standards.
Ms. Peterson and Messrs. Austin and Fredrickson do not serve as an executive officer of any nonprofit organization to which we or our affiliates made contributions within any single year of the preceding three years that exceeded the greater of $1.0 million or 2 percent of such organization’s consolidated gross revenues. Further, there were no discretionary contributions made by us or our affiliates to a nonprofit organization with which such director, or such director’s spouse, has a relationship that impact the director’s independence.
Meeting Attendance and Preparation
Members of the Board of Directors of our general partner are expected to attend at least 75 percent of regular Board meetings and meetings of the committees on which they serve, either in person or telephonically. In addition, directors are expected to be prepared for each meeting of the Board by reviewing written materials distributed in advance.
Executive Sessions of NonManagement Directors
Our general partner’s nonmanagement Board members periodically meet outside the presence of our general partner’s executive officers. The Chair of the Audit Committee serves as the presiding director for executive sessions of nonmanagement Board members. The current Chair of the Audit Committee and the presiding director is Ms.  Peterson.
Communications with Directors
Interested parties wishing to communicate with our general partner’s nonmanagement directors, individually or as a group, may do so by contacting our general partner’s Corporate Secretary or the presiding director. The contact information is maintained at the corporate responsibility/corporate governance guidelines tab of our website at http://investor.williams.com/williams-partners-lp.
The current contact information is as follows:
Williams Partners L.P.
c/o WPZ GP LLC
One Williams Center, Suite 4700
Tulsa, Oklahoma 74172
Attn: Presiding Director
Williams Partners L.P.
c/o WPZ GP LLC
One Williams Center, Suite 4700
Tulsa, Oklahoma 74172
Attn: Corporate Secretary

148



Board Committees
The Board of Directors of our general partner has a separately designated standing Audit Committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934 and a Conflicts Committee. The following is a description of each of the committees and current committee membership.
Board Committee Membership 
 
Audit
 
Conflicts
 
Committee
 
Committee
H. Brent Austin
ü
 
Philip L. Fredrickson
ü
 
ü
Alice M. Peterson
 
ü
_______________
ü  = committee member
•    = chairperson
Audit Committee
Our general partner’s Board of Directors has determined that all members of the Audit Committee meet the heightened independence requirements of the NYSE for audit committee members and that all members are financially literate as defined by the rules of the NYSE. The Board of Directors has further determined that all members of the Audit Committee qualify as “audit committee financial experts” as defined by the rules of the SEC. Biographical information for each of these persons is set forth above. The Audit Committee is governed by a written charter adopted by the Board of Directors. For further information about the Audit Committee, please read the “Report of the Audit Committee” below and “Principal Accountant Fees and Services.”
Conflicts Committee
The Conflicts Committee of our general partner’s Board of Directors reviews specific matters that the Board believes may involve conflicts of interest. The Conflicts Committee determines if resolution of the conflict is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates and must meet the independence and experience requirements established by the NYSE and other federal securities laws. Any matters approved by the Conflicts Committee will be conclusively deemed fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe to us or our unitholders.
Code of Business Conduct and Ethics
Our general partner has adopted a Code of Business Conduct and Ethics for directors, officers and employees. We intend to disclose any amendments to or waivers of the Code of Business Conduct and Ethics on behalf of our general partner’s Chief Executive Officer, Chief Financial Officer, Controller and persons performing similar functions on our website at http://investor.williams.com/williams-partners-lp. under the Corporate Governance tab, promptly following the date of any such amendment or waiver.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our general partner’s executive officers and directors and persons who own more than 10 percent of a registered class of our equity securities to file with the SEC and the NYSE reports of ownership of our securities and changes in reported ownership. Executive officers and directors of our general partner and greater than 10 percent unitholders are required by SEC rules to furnish to us copies of all Section 16(a) reports that they file. Based solely on a review of reports furnished to our general partner, or written representations from reporting persons that all reportable transactions were reported, we believe that during the fiscal year ended December 31, 2015 our general partner’s officers, and directors and our greater than 10 percent common unitholders timely filed all reports they were required to file under Section 16(a).

149



Transfer Agent and Registrar
Computershare Trust Company, N.A. serves as registrar and transfer agent for our common units. Contact information for Computershare is as follows:
Computershare Trust Company, N.A.
P.O. Box 30170
College Station, Texas 77842-3170
Phone: (781) 575-2879 or toll-free, (877) 498-8861
Hearing impaired: (800) 952-9245
Internet: www.computershare.com/investor
Send overnight mail to:
Computershare Trust Company, N.A.
211 Quality Circle, Suite 210
College Station, Texas 77845

150



REPORT OF THE AUDIT COMMITTEE
The Audit Committee oversees our financial reporting process on behalf of the Board of Directors. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls. The Audit Committee operates under a written charter approved by the Board. The charter, among other things, provides that the Audit Committee has authority to appoint, retain, oversee and terminate when appropriate the independent auditor. In this context, the Audit Committee:
 
Reviewed and discussed the audited financial statements in this annual report on Form 10-K with management, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements;
Reviewed with Ernst & Young LLP, the independent auditors, who are responsible for expressing an opinion on the conformity of those audited financial statements with generally accepted accounting principles, their judgments as to the quality and acceptability of Williams Partners L.P.’s accounting principles and such other matters as are required to be discussed with the Audit Committee under generally accepted auditing standards;
Received the written disclosures and the letter from Ernst & Young LLP required by applicable requirements of the Public Company Accounting Oversight Board regarding Ernst & Young LLP’s communications with the audit committee concerning independence, and discussed with Ernst & Young LLP its independence;
Discussed with Ernst & Young LLP the matters required to be discussed by Auditing Standard No. 16, “Communications with Audit Committees” issued by the Public Company Accounting Oversight Board;
Discussed with Williams Partners L.P.’s internal auditors and Ernst & Young LLP the overall scope and plans for their respective audits. The Audit Committee meets with the internal auditors and Ernst & Young LLP, with and without management present, to discuss the results of their examinations, their evaluations of Williams Partners L.P.’s internal controls and the overall quality of Williams Partners L.P.’s financial reporting; and
Based on the foregoing reviews and discussions, recommended to the Board of Directors that the audited financial statements be included in the annual report on Form 10-K for the year ended December 31, 2015, for filing with the SEC.
This report has been furnished by the members of the Audit Committee of the Board of Directors:
— Alice M. Peterson - Chair
— H. Brent Austin
— Philip L. Fredrickson
The report of the Audit Committee in this report shall not be deemed incorporated by reference into any other filing by Williams Partners L.P. under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under such acts.
Item 11. Executive Compensation
Compensation Discussion and Analysis
We are managed by the executive officers of our general partner who are also executive officers of Williams. Neither we nor our general partner have a compensation committee. The executive officers of our general partner are compensated directly by Williams. All decisions as to the compensation of the executive officers of our general partner who are involved in our management are made by the Compensation Committee of Williams. Therefore, we do not have any policies or programs relating to compensation of the executive officers of our general partner and we make no decisions relating to such compensation. None of the executive officers of our general partner have employment agreements with us or are otherwise specifically compensated for their service as an executive officer of our general partner. A full discussion of the policies and programs of the Compensation Committee of Williams will be set forth

151



in the Williams’ Form 10-K filing which will be available upon its filing on the SEC’s website at www.sec.gov and on Williams’ website at www.williams.com at the “Investors - SEC Filings” tab (Williams’ Annual Reports). Williams’ Form 10-K will also be available free of charge from the Corporate Secretary of our general partner. We reimburse our general partner for direct and indirect general and administrative expenses attributable to our management (which expenses include the share of the compensation paid to the executive officers of our general partner attributable to the time they spend managing our business). Please read “Certain Relationships and Related Transactions, and Director Independence - Reimbursement of Expenses of Our General Partner” for more information regarding this arrangement.
Executive Compensation
The following table summarizes the compensation attributable to services performed for us in 2015 for our general partner’s named executive officers (NEOs), consisting of our principal executive officer, principal financial officer, and three other most highly compensated executive officers.
Further information regarding compensation of our principal executive officer, Mr. Armstrong, who also serves as the President and Chief Executive Officer of Williams, our principal financial officer, Mr. Chappel, who also serves as the Senior Vice President and Chief Financial Officer of Williams, our Senior Vice President - Central Operating Area & Operational Excellence, Mr. Purgason, who serves as Senior Vice President - Central Operating Area & Operational Excellence of Williams, our Senior Vice President - Engineering & Construction, Mr. Seldenrust, who serves as Senior Vice President - Engineering & Construction of Williams and our Senior Vice President - Atlantic-Gulf, Mr. Miller, who serves as our Senior Vice President - Atlantic - Gulf and who also serves as Senior Vice President - Atlantic - Gulf of Williams, will be set forth in Williams’ Form 10-K filing. Compensation amounts set forth in Williams’ Form 10-K filing will include all compensation paid by Williams, including the amounts in the table below attributable to services performed for us.

152



2015 Summary Compensation Table
The following table sets forth certain information with respect to Williams’ compensation of our general partner’s NEOs attributable to us during fiscal years 2015, 2014, and 2013:  
Name and
Principal Position (1)
Year
Salary
Bonus
Stock Awards (2)
Option Awards (3)
Non-Equity Incentive Plan Compensation (4)
Change in Pension Value and Nonqualified Deferred Compensation Earnings (5)
All Other Compensation (6)
Total
Alan S. Armstrong
2015
$
1,100,925

$

$
4,024,297

$
1,152,621

$
1,128,905

$
(568,869
)
$
40,772

$
6,878,652

President and Chief
2014








Executive Officer
2013








Donald R. Chappel
2015
658,534


1,433,184

400,993

598,224

(253,539
)
20,159

2,857,555

SVP, Chief Financial
2014








Officer
2013








Robert S. Purgason
2015
531,558


1,449,125

405,453

310,000

88,676

29,930

2,814,742

SVP, Central OA and
2014
455,192

661,693

6,105,737


30,024,798


247,731

37,495,151

Operational Excellence
2013
448,269

581,050

250,221


263,899


40,700

1,584,139

John D. Seldenrust
2015
429,579


1,137,565

93,743

707,231

55,545

22,046

2,445,708

SVP, Engineering and
2014
390,454

371,241

5,102,763




163,446

6,027,904

Construction
2013
371,077

351,650

315,180




24,906

1,062,813

Rory L. Miller
2015
487,692


1,086,877

304,088

310,000

(201,730
)
16,848

2,003,775

SVP, Atlantic - Gulf
2014








 
2013








___________
(1)
Name and Principal Position. Mr. Seldenrust was elected to his current position effective July 1, 2015.
(2)
Stock Awards. Awards were granted under the terms of Williams’ 2007 Incentive Plan and include time-based and performance-based restricted stock units (RSUs). Amounts shown are the grant date fair value of awards attributable to us computed in accordance with FASB ASC Topic 718. The assumptions used by Williams to determine the grant date fair value of the stock awards can be found in the Williams Annual Report on Form 10‑K for the year-ended December 31, 2015.
The potential maximum values attributable to us of the performance-based RSUs, subject to changes in performance outcomes of Williams, are as follows:
 
 
2015 Performance-Based RSU Maximum Potential
Alan S. Armstrong
 
$
5,205,813

Donald R. Chappel
 
1,481,780

Robert S. Purgason
 
1,498,261

John D. Seldenrust
 
312,967

Rory L. Miller
 
1,123,713


153



(3)
Option Awards. Awards are granted under the terms of Williams’ 2007 Incentive Plan and include nonqualified stock options. Amounts shown are the grant date fair value of awards attributable to us computed in accordance with FASB ASC Topic 718. The assumptions used by Williams to determine the grant date fair value of the option awards can be found in the Williams Annual Report on Form 10-K for the year-ended December 31, 2015. The options may be exercised to acquire Williams’ common stock. The NEOs do not receive any option awards from us.
(4)
Non-Equity Incentive Plan. Williams provides an annual incentive program to the NEOs and payments are based on the financial performance of Williams. The maximum annual incentive pool funding for NEOs is 250 percent of target. We do not sponsor any non-equity incentive plans. Mr. Chappel’s annual incentive award includes an additional $165,000 awarded by the Compensation Committee recognizing Mr. Chappel’s outstanding contribution in support of the strategic alternatives review process conducted by the Board. Mr. Seldenrust’s 2015 amount includes annual incentive award and a special engineering and construction incentive award of $500,000. Mr. Purgason’s 2013 and 2014 data reflect amounts earned from an award made by ACMP in December 2012 pursuant to the Excess Return Component of their Management Incentive Compensation Plan (MICP).  The amounts were paid pro-rata to Mr. Purgason over the remaining years of the MICP, until July 1, 2014 when both components of the MICP vested and paid with the ACMP Merger.
(5)
Change in Pension Value and Nonqualified Deferred Compensation Earnings. The amount shown is the aggregate change from December 31, 2014 to December 31, 2015 in the actuarial present value of the accrued benefit under the qualified pension and non-qualified plan. The primary reasons for the decrease in the change in present value is a higher discount rate used to measure these benefits at the end of 2015. Mr. Purgason and Mr. Seldenrust show an increase in the present value in 2015 as they did not have an accrued benefit as of December 31, 2014. The underlying design of these programs did not change from 2014 to 2015. Please refer to the “Pension Benefits” table for further details of the present value of the accrued benefit.
(6) All Other Compensation. Amounts shown represent payments made on behalf of the NEOs and include life insurance premiums, a 401(k) matching contribution, tax gross-ups on the imputed income related to spousal travel for business purposes and perquisites (if applicable). Perquisites may include financial planning services, mandated annual physical exam and personal use of the Company aircraft. If the NEO used the Company aircraft, the incremental cost method is used to calculate the personal use of the Company aircraft. The incremental cost calculation includes such items as fuel, maintenance, weather and airport services, pilot meals, pilot overnight expenses, aircraft telephone and catering. Details of perquisites for Mr. Armstrong and Mr. Purgason are included because the individual aggregate amounts exceed $10,000. Amounts do not include arrangements that are generally available to our employees and do not discriminate in scope, terms or operations in favor of our NEOs, such as relocation, medical, dental, and disability programs.
 
 
Financial Planning
 
Annual Physical Exam
 
Company Aircraft Personal Usage
Alan S. Armstrong
 
$
4,942

 
$
1,631

 
$
10,438

Robert S. Purgason
 
15,000

 
4,654

 


154



Outstanding WPZ Equity Awards
The following table sets forth information with respect to the outstanding equity awards held by the NEOs at the end of 2015.
 
Option Awards
 
Stock Awards
Name
Grant Date
Number of Securities Underlying Exercised Options (#) Exercisable
Number of Securities Underlying Exercised Options (#) Unexercisable
Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options
Option Exercise Price
Expiration Date
 
Grant Date
Number of Shares or Units of Stock That Have Not Vested
Market Value of Shares or Units of Stock That Have Not Vested
Equity Incentive Plan Awards: Number of Unearned Shares, Units of Stock or Other Rights That Have Not Vested (1)
Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested (2)
Armstrong
 
 
 
 
 
 
 
 
 
 


Chappel
 
 
 
 
 
 
 
 
 
 


Purgason
 
 
 
 
 
 
 
7/16/2014
 
 
83,075

$
2,313,639

Seldenrust
 
 
 
 
 
 
 
7/16/2014
 
 
66,460

1,850,911

Miller
 
 
 
 
 
 
 
 
 
 


__________
Note: Information provided is as of the close of market on December 31, 2015.
(1)
The time-based WPZ RSU awards granted to Mr. Purgason and Mr. Seldenrust on July 16, 2014 are on a four-year graded vesting schedule. The first 25 percent will vest on July 16, 2016, the second 25 percent will vest on July 16, 2017, with the final 50 percent vesting on July 16, 2018. These awards were adjusted on February 2, 2015 as part of the WPZ and ACMP merger by a ratio of 1.06152 WPZ shares for every one ACMP share. The final values on the table above reflect the awards after the adjustment was applied.
(2)
Values are based on a closing WPZ stock price of $27.85 on December 31, 2015.
We have not included tables with information about grants of plan-based awards as there were not any WPZ equity awards to NEOs in 2015. We also did not include an Options Exercised and Stock Vested table as the NEOs did not receive any WPZ equity award distributions in 2015. Additionally, pension benefits, and nonqualified deferred compensation tables are not included because we do not currently sponsor such plans. In addition, our NEOs are not entitled to any compensation as a result of a WPZ change-in-control or the termination of their service as an NEO of our general partner. Information related to Williams’ sponsorship of any such plans is set forth in Williams’ Form 10‑K.
Compensation Committee Interlocks and Insider Participation
As previously discussed, our general partner’s Board of Directors is not required to maintain, and does not maintain, a compensation committee. During 2015, all compensation decisions with respect to our NEOs were made by the Compensation Committee of the Board of Directors of Williams, which is comprised entirely of independent members of Williams’ Board. In addition, none of these individuals receive any compensation directly from us or our general partner. Please read “Certain Relationships and Related Transactions, and Director Independence” below for information about relationships among us, our general partner and Williams.
Compensation Policies and Practices as They Relate to Risk Management
We do not have any employees. We are managed and operated by the directors and officers of our general partner and employees of Williams perform services on our behalf. We do not have any compensation policies or practices that need to be assessed or evaluated for the effect on our operations. Please read “Compensation Discussion and Analysis,” “Employees,” and “Certain Relationships and Related Transactions, and Director Independence” for more information about this arrangement. For an analysis of any risks arising from Williams’ compensation policies and practices, please read Williams’ Form 10-K.

155



Board Report on Compensation
Neither we nor our general partner has a compensation committee. The Board of Directors of our general partner has reviewed and discussed with management the Compensation Discussion and Analysis set forth above and based on this review and discussion has approved it for inclusion in this Form 10-K.
The Board of Directors of WPZ GP LLC:
Alan S. Armstrong,
H. Brent Austin,
Frank E. Billings,
Donald R. Chappel,
Philip L. Frederickson,
Rory L. Miller,
Alice M. Peterson,
Robert S. Purgason,
James E. Scheel
The Board Report on Compensation in this report shall not be deemed incorporated by reference into any other filing by Williams Partners L.P. under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under such acts.
Compensation of Directors
We are managed by the Board of Directors of our general partner. Members of the Board of Directors who are also officers or employees of Williams or an affiliate of us or Williams do not receive additional compensation for serving on the Board of Directors. Please read “Compensation Discussion and Analysis,” “Executive Compensation,” and “Certain Relationships and Related Transactions, and Director Independence - Reimbursement of Expenses of Our General Partner” for information about how we reimburse our general partner for direct and indirect general and administrative expenses attributable to our management. Non-employee directors receive a bi-annual compensation package consisting of the following, which amounts are paid on January 1 and July 1: (a) $75,000 cash retainer; and (b) $5,000 cash retainer each for service on the Conflicts Committee or Audit Committee of the Board of Directors. If a non-employee director’s service on the Board of Directors commenced after January 1 and prior to the final day of June, or after July 1 and prior to December 31, the non-employee director receives a prorated bi-annual compensation at the time of the next scheduled bi-annual payment. Also, each non-employee director serving as a member of the Conflicts Committee receives $1,250 cash for each Conflicts Committee meeting attended by such director. Fees for attendance at meetings of the Conflicts Committee are paid on January 1 and July 1 for meetings held during the preceding months. Additionally, Mr. Frederickson and former Directors, Mr. David A. Daberko and Ms. Suedeen G. Kelly, received cash payments of $75,000, $60,000, and $60,000, respectively, for serving as members of the Conflicts Committee of ACMP, in connection with the ACMP Merger.
Each non-employee director is also reimbursed for out-of-pocket expenses in connection with attending meetings of the Board of Directors or its committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law. We also reimburse non-employee directors for the costs of education programs relevant to their duties as Board members.

156



For their service, non-management directors earned the following compensation in 2015:
Director Compensation Fiscal Year 2015
Name
 
Fees Earned of Paid in Cash (1)
 
Unit Awards
 
Option Awards
 
Nonequity Incentive Plan Compensation
 
Change in Pension Value and Nonqualified Deferred Compensation Earnings
 
All Other Compensation
 
Total
H. Brent Austin (2)
 
$
177,917

 
$

 
$

 
$

 
$

 
$

 
$
177,917

David A. Daberko (3) (6)
 
233,750

 

 

 

 

 

 
233,750

Philip L. Frederickson (7)
 
248,750

 

 

 

 

 

 
248,750

Suedeen G. Kelly (4) (6)
 
135,000

 

 

 

 

 

 
135,000

Alice M. Peterson (2)
 
177,917

 

 

 

 

 

 
177,917

Michael J. Stice (5)
 
75,000

 

 

 

 

 

 
75,000

__________
(1)
Bi-annual compensation retainer fees and Conflicts Committee meeting fees paid in 2015 are reflected in this column.
(2)
Mr. Austin and Ms. Peterson joined the Board effective February 2, 2015.
(3)
Mr. Daberko resigned from the Board effective December 3, 2015.
(4)
Ms. Kelly resigned from the Board effective February 2, 2015.
(5)
Mr. Stice resigned from the Board effective May 13, 2015.
(6)
Mr. Daberko and Ms. Kelly each received a $60,000 cash payment in recognition of additional work associated with the ACMP Merger.
(7)
Mr. Frederickson received a $75,000 cash payment in recognition of additional work associated with the ACMP Merger.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following tables set forth the beneficial ownership by holders of (i) our common units and other classes of equity and (ii) shares of Williams that, unless otherwise noted, as of February 16, 2016, are held by:
Each member of our general partner’s Board of Directors;
Each named executive officer of our general partner;
All directors and executive officers of our general partner as a group; and
Each person or group of persons known by us to be a beneficial owner of 5 percent or more of the then outstanding common units and Class B units.
The amounts and percentage of units or shares beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he or she has no economic interest. Except as indicated by footnote, the persons named in the tables below have sole voting

157



and investment power with respect to all units or shares shown as beneficially owned by them, subject to community property laws where applicable.
Williams Partners Beneficial Ownership
Name of Beneficial Owner
 
Common Units
 
Percentage of
Common
Units (1)
 
Class B Units
 
Percentage of Class B Units
The Williams Companies, Inc.(2)
 
339,664,088

 
57.71%
 
15,343,001

 
100.00%
Alan S. Armstrong (3)
 
32,334

 
*
 

 
H. Brent Austin
 
8,958

 
*
 

 
Frank E. Billings
 

 
*
 

 
Donald R. Chappel
 
19,574

 
*
 

 
Philip L. Fredrickson
 
23,577

 
*
 

 
Rory L. Miller
 
1,752

 
*
 

 
Alice M. Peterson
 
3,921

 
*
 

 
Robert S. Purgason
 
29,726

 
*
 

 
James E. Scheel
 

 
*
 

 
John D. Seldenrust
 
1,262

 
*
 

 
All executive officers and directors of general partner as a group (16 persons)
 
130,658

 
*
 

 
____________
* Less than 1 percent.
(1)
The percentage of beneficial ownership is based on 588,565,174 common units outstanding as of February 16, 2016.
(2)
This row includes ownership information of Williams Gas Pipeline Company, LLC, which is controlled by Williams and directly held 339,664,088 Common Units and 15,343,001 Class B Units as of February 16, 2016.
(3)
Includes 8,667 common units indirectly held by the Shelly Stone Armstrong Trust, dated June 16, 2010 and 23,667 common units indirectly held by the Alan Stuart Armstrong Trust, dated June 16, 2010.
Williams Beneficial Ownership
Name of Beneficial Owner
 
Shares of Common Stock Owned Directly or Indirectly
 
Shares Underlying Stock Options (1)
 
Shares Underlying Restricted Stock Units (2)
 
Total
 
Percent of Class (3)
Alan S. Armstrong (4)
 
312,940

 
797,452

 
38,497

 
1,148,889

 
*
H. Brent Austin
 

 

 

 

 
*
Frank E. Billings
 
20,043

 
30,791

 
14,253

 
65,087

 
*
Donald R. Chappel
 
292,659

 
725,818

 
46,376

 
1,064,853

 
*
Philip L. Fredrickson
 

 

 

 

 
*
Rory L. Miller
 
104,948

 
213,688

 
27,485

 
346,121

 
*
Alice M. Peterson
 

 

 

 

 
*
Robert S. Purgason
 

 
53,279

 
5,539

 
58,818

 
*
James E. Scheel (5)
 
14,067

 
136,077

 
15,349

 
165,493

 
*
John D. Seldenrust
 

 
4,126

 

 
4,126

 
*
All current directors and executive officers as a group (16 persons)
 
805,947

 
2,369,489

 
239,555

 
3,414,991

 
*
_____________
*
Less than 1 percent.
(1)
Amounts reflect Williams shares that may be acquired upon the exercise of stock options granted under Williams’ current or previous equity plans that are currently exercisable, will become exercisable, or would be exercisable upon the voluntary retirement of such person, within 60 days of February 16, 2016.

158



(2)
Amounts reflect Williams shares that would be acquired upon the vesting of restricted stock units granted under Williams’ current or previous equity plans that will vest or that would vest upon the voluntary retirement of such person, within 60 days of February 16, 2016. Restricted stock units have no voting or investment power.
(3)
Ownership percentage is reported based on 588,565,174 shares of Williams common stock outstanding on February 16, 2016, plus, as to the holder thereof only and no other person, the number of shares (if any) that the person has the right to acquire as of February 16, 2016 or within 60 days from that date, through the exercise of all options and other rights.
(4)
Shares of Common Stock amount reflect 34,264 shares in the Alan and Shelly Armstrong Foundation dated December 16, 2015, Alan Armstrong and Shelly Armstrong, Trustees.
(5)
Shares of Common Stock amount reflect 4,345 shares in the Scheel Family Foundation dated October 2, 2014, James E. and Judith V. Scheel, Trustees.
Securities authorized for issuance under equity compensation plans
The following table sets forth information with respect to the securities that may be issued under our long-term incentive plans as of December 31, 2015.
Plan Category
 
Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights
 
Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights
 
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column)
Equity compensation plans approved by security holders
 

 
 

Equity compensation plans not approved by security holders (1) (2)
 
1,184,325

 
N/A
 
1,341,094

_____________
(1)
Amounts presented reflect the Williams Partners L.P. Long-Term Incentive Plan, as adopted by the Board of Directors of our general partner in 2010. Amounts presented have been adjusted for the effects of the ACMP Merger.
(2)
The table does not include securities available for future issuance under Pre-merger WPZ’s long-term incentive plan, which was adopted by the Board of Directors of its general partner in 2005. We assumed this plan as a result of the ACMP Merger. As of December 31, 2015, 686,597 of these securities were available for issuance under this plan. The number of awards that may be issued under this plan in the future is subject to conversion to our securities by our general partner to reflect the effect of the ACMP Merger. No awards were outstanding under this plan as of December 31, 2015.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Transactions with Related Persons
At February 16, 2016, an affiliate of our general partner owns 339,664,088 common units and 15,343,001 Class B units representing a combined 58 percent limited partner interest in us. Williams also owns 100 percent of our general partner, which allows it to control us. Certain officers and directors of our general partner also serve as officers and/or directors of Williams. Our general partner owns a 2 percent general partner interest and incentive distribution rights in us.
In addition to the related transactions and relationships discussed below, information about such transactions and relationships is included in Note 5 – Related Party Transactions of our Notes to Consolidated Financial Statements and is incorporated into this Item 13 by reference.

159



Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments made or to be made by us to our general partner and its affiliate in connection with our ongoing operation and upon our liquidation, if any. These distributions and payments were determined by and among affiliated entities.
 
 
Operational Stage
 
 
 
Distributions of available cash to our general partner and its affiliate
 
We generally make cash distributions 98 percent to our unitholders pro rata, including Williams as the holders of an aggregate 58 percent of common units and 2 percent to our general partner at December 31, 2015, assuming it makes any capital contributions necessary to maintain its 2 percent interest in us.
 
 
 
 
 
In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner is entitled to increasing percentages of the distributions, up to 50 percent of the distributions above the highest target distribution level. If our general partner elects to reset the target distribution levels, it will be entitled to receive common units and to maintain its general partner interest.
 
 
 
 
 
We refer to the rights to the increasing distributions as “incentive distribution rights.” Our general partner agreed to temporarily waive a portion of incentive distributions in connection with the execution of the Termination Agreement and certain interests acquired in 2015. For further information about distributions, please read “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities-” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Management’s Discussion and Analysis of Financial Condition and Liquidity.”
 
 
 
Payments to our general partner and its affiliates
 
Please read “—Reimbursement of Expenses of Our General Partner” below.
 
 
 
Withdrawal or removal of our general partner
 
If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
 
 
 
 
 
Liquidation Stage
 
 
 
Liquidation
 
Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
Reimbursement of Expenses of Our General Partner
Our general partner does not receive any management fee or other compensation for its management of our business. We reimburse our general partner for expenses incurred on our behalf, including expenses incurred in compensating employees of an affiliate of Williams who perform services on our behalf. These expenses include all allocable expenses necessary or appropriate to the conduct of our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. There is no minimum or maximum amount that may be paid or reimbursed to our general partner for expenses incurred on our behalf. These expenses will include our allocable share of salaries, non-equity incentive plan compensation, and other employment-related expenses, including Williams restricted stock unit and stock option awards, retirement plans, health and welfare plans, employer-related payroll taxes, matching contributions made under a Williams defined contribution plan and premiums for life insurance.
Our general partner allocated expenses to us for the services performed on our behalf by our executive officers, who are also employees of Williams, and those of our directors, who are also employees of Williams. This allocated expense of $35 million, included our allocable share of salaries, non-equity incentive plan compensation, and other employment-related expenses, including Williams restricted stock unit and stock option awards, retirement plans, health and welfare plans, employer-related payroll taxes, matching contributions made under a Williams defined contribution plan and premiums for life insurance.

160



Williams affiliates charge us for the costs associated with the employees that operate our assets. In addition, general and administrative services are provided to us by employees of Williams, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our operations. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of the costs of doing business incurred by Williams. These services are provided to Transco and Northwest Pipeline pursuant to separate administrative service agreements with an affiliate of Williams.
Summary of Other Transactions Involving Williams and its Affiliates
ACMP Merger
See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements for a discussion of the ACMP Merger on February 2, 2015.
Public Unit Exchange
See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements for a discussion of the Public Unit Exchange.
Construction Services
HB Construction Company Ltd., a subsidiary of Williams, provides construction services to us at market prices.
Operating Agreements with Equity Method Investees
We are party to operating agreements with unconsolidated companies where our investment is accounted for using the equity method. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies and other charges and also for management services. Williams supplied a portion of these services, primarily those related to employees since we do not have any employees, to the equity-method investees. Amounts are billed to the equity-method investments the partnership operates.
Quarterly Cash Distributions
For the year ended December 31, 2015, we distributed approximately $1.8 billion to affiliates of Williams as quarterly distributions on our common units, the 2 percent general partner interest, and the general partner’s incentive distribution rights.
Initial Omnibus Agreement
Upon the closing of Pre-merger WPZ’s initial public offering (IPO) in 2005, Pre-merger WPZ entered into an omnibus agreement with Williams and its affiliates that was not the result of arm’s-length negotiations. The omnibus agreement continues to govern our relationship with Williams regarding the following matters in connection with our IPO: 
Indemnification for certain environmental liabilities and tax liabilities;
Reimbursement for certain expenditures; and
A license for the use of certain software and intellectual property.
Total amounts received under this agreement for the year ended December 31, 2015, were less than $1 million.
February 2010 Omnibus Agreement
In connection with Williams’ contribution of ownership interests in certain entities to Pre-merger WPZ in February 2010, Pre-merger WPZ entered into an omnibus agreement with Williams. Pursuant to this omnibus agreement, Williams

161



remains obligated to indemnify us for an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received prior to the closing of the contribution transaction for services to be rendered by us in the future at the Devils Tower floating production platform located in Mississippi Canyon Block 773. Amounts received under this agreement for the year ended December 31, 2015, were $11 million. In 2010, Pre-merger WPZ also entered into a contribution agreement with Williams in connection with this transaction. The contribution agreement continues to govern our relationship with Williams with respect to indemnification for certain tax liabilities.
Canada Acquisition
Basis of Presentation in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies includes related party transactions for the Canada Acquisition.
We became party to various ancillary agreements with affiliates of Williams related to the transaction, including agreements that provide for:
Certain rights to access and use the acquired facilities by Williams affiliates so Williams may continue to develop additional projects;
Development of future projects by the parties;
Employees of Williams to operate the acquired assets and the allocation of costs related to the operation of those assets.
Intellectual Property License
Williams and its affiliates granted a license to us for the use of certain marks, including our logo, for as long as Williams controls our general partner, at no charge.
Equity Issuances
In connection with equity issuances under our shelf registration, our general partner contributed $1.2 million to maintain its 2 percent general partnership interest. (See Note 14 – Partners’ Capital of Notes to Consolidated Financial Statements.)
In connection with Class B issuances discussed in Note 4 – Allocation of Net Income (Loss) and Distributions of Notes to Consolidated Financial Statements, our general partner contributed $1.1 million to maintain its 2 percent general partnership interest.
Review, Approval or Ratification of Transactions with Related Persons
Our partnership agreement contains specific provisions that address potential conflicts of interest between our general partner and its affiliates, including Williams, on one hand, and us and our subsidiaries, on the other hand. Whenever such a conflict of interest arises, our general partner will resolve the conflict. Our general partner may, but is not required to, seek the approval of such resolution from the Conflicts Committee of the Board of Directors of our general partner, which is comprised of independent directors. The partnership agreement provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or to our unitholders if the resolution of the conflict is: 
Approved by the Conflicts Committee;
Approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
On terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

162



Fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.
If our general partner does not seek approval from the Conflicts Committee and the Board of Directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the Conflicts Committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires. See “Directors, Executive Officers and Corporate Governance — Governance — Board Committees — Conflicts Committee.”
In addition, our Code of Business Conduct and Ethics requires that all employees, including employees of affiliates of Williams who perform services for us and our general partner, avoid or disclose any activity that may interfere, or have the appearance of interfering, with their responsibilities to us and our unitholders. Conflicts of interest that cannot be avoided must be disclosed to a supervisor who is then responsible for establishing and monitoring procedures to ensure that we are not disadvantaged.
Director Independence
Please read “Directors, Executive Officers and Corporate Governance — Governance — Director Independence” and “ — Board Committees” in Item 10 above for information about the independence of our general partner’s Board of Directors and its committees, which information is incorporated into this Item 13 by reference.

Item 14. Principal Accountant Fees and Services
We have engaged Ernst & Young LLP (and previously PricewaterhouseCoopers LLP) as our independent registered public accounting firm. The following table summarizes the fees we have paid to both firms to audit the Partnership’s annual consolidated financial statements and for other services for each of the last two fiscal years:
 
2015
 
2014
 
(Millions)
Audit Fees
$
6.6

 
$
2.6

Audit-Related Fees
0.4

 

Tax Fees

 
0.6

All Other Fees

 

 
$
7.0

 
$
3.2

Fees for audit services in 2015 and 2014 include fees associated with the annual audit, the reviews of our quarterly reports on Form 10-Q, the audit of our assessment of internal controls as required by Section 404 of the Sarbanes-Oxley Act of 2002 and services provided in connection with other filings with the SEC. Audit fees in 2014 relate to the audit of Access Midstream Partners, L.P. prior to the merger with Williams Partners, L.P. in 2015. The fees for audit services do not include audit costs for stand-alone audits for equity investees. Audit-Related fees include services under certain agreed-upon procedures for other compliance purposes. Tax fees for 2015 and 2014 include fees for review of our federal tax return. Ernst & Young LLP does not provide tax services to our general partner’s executive officers.
The Audit Committee of our general partner’s Board of Directors is responsible for appointing, setting compensation for and overseeing the work of Ernst & Young LLP, our independent auditor. The Audit Committee has established a policy regarding pre-approval of all audit and non-audit services provided by Ernst & Young LLP. On an ongoing basis, our general partner’s management presents specific projects and categories of service to the Audit Committee to request advance approval. The Audit Committee reviews those requests and advises management if the Audit Committee approves the engagement of Ernst & Young LLP. On a quarterly basis, the management of our general partner reports to the Audit Committee regarding the services rendered by, including the fees of, the independent accountant in the previous quarter and on a cumulative basis for the fiscal year. The Audit Committee may also delegate the ability to

163



pre-approve audit and permitted non-audit services, excluding services related to our internal control over financial reporting, to any two committee members, provided that any such pre-approvals are reported at a subsequent Audit Committee meeting. In 2015 and 2014, 100 percent of Ernst & Young LLP’s and and PricewaterhouseCoopers LLP’s fees were pre-approved by the Audit Committee.
Change of Independent Registered Accounting Firm
ACMP merged with Pre-merger Williams Partners in February 2015. The Audit Committee of our general partner’s Board of Directors dismissed PricewaterhouseCoopers LLP (“PwC”) as the independent registered public accounting firm upon the filing of Quarterly Report on Form 10-Q for the quarter ended September 30, 2014. The Audit Committee approved the appointment of EY as our independent registered public accounting firm for the fiscal year ended December 31, 2014.
PwC’s audit reports on our consolidated financial statements for each of the two fiscal years ended December 31, 2013 and 2012 did not contain an adverse opinion or a disclaimer of opinion, and were not qualified or modified as to uncertainty, audit scope, or accounting principles. During the two fiscal years ended December 31, 2013 and 2012, and in the subsequent interim period through October 30, 2014, there were (i) no disagreements with PwC on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreement, if not resolved to the satisfaction of PwC, would have caused PwC to make reference to the subject matter of the disagreement in its reports on the consolidated financial statements for such years, and (ii) no “reportable events” within the meaning of Item 304(a)(1)(v) of the SEC’s Regulation S-K.
In connection with the audits of our consolidated financial statements, during the two fiscal years ended December 31, 2013 and 2012 and subsequent interim period through October 30, 2014, neither us, our general partner, nor anyone on each of our behalf consulted with EY regarding (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on our financial statements, and neither a written report nor oral advice was provided to us or our general partner that EY concluded was an important factor considered by us or our general partner in reaching a decision as to the accounting, auditing, or financial reporting issue; or (ii) any matter that was either the subject of a “disagreement” (as that term is defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions to Item 304 of Regulation S-K) or a “reportable event” (as that term is defined in Item 304(a)(1)(v) of Regulation S-K).
We previously reported this information in our Current Report on Form 8-K dated October 3, 2014, as amended on November 4, 2014.


164



PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) 1 and 2. Williams Partners L.P. financials
All other schedules have been omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and notes thereto.

(a)
3 and (b). The following documents are included as exhibits to this report:
INDEX TO EXHIBITS
Exhibit
Number
 
 
 
Description
 
 
 
 
 
2.1§
 
 
Agreement and Plan of Merger dated as of May 12, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May 13, 2015 as Exhibit 2.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
3.1
 
 
Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. (filed on February 16, 2010 as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905 and incorporated herein by reference).

 
 
 
 
 
3.2
 
 
Amendment to Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. (filed on July 30, 2012 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.3
 
 
Amendment to Certificate of Limited Partnership of Access Midstream Partners, L.P. (filed on February 3, 2015 as Exhibit 3.5 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.4
 
 
Composite Certificate of Limited Partnership of Williams Partners L.P. (filed on February 25, 2015 as Exhibit 3.4 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.5
 
 
First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P., dated August 3, 2010 (filed on August 5, 2010 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.6
 
 
Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. dated as of July 24, 2012 (filed on July 30, 2012 as Exhibit 3.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 



Exhibit
Number
 
 
 
Description
 
 
 
 
 
3.7
 
 
Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of December 20, 2012 (filed on December 26, 2012 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
3.8
 
 
Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of January 29, 2015 (filed on February 3, 2015 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.9
 
 
Amendment No. 4 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of January 29, 2015 (filed on February 3, 2015 as Exhibit 3.4 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
3.10
 
 
Amendment No. 5 to the First Amended and Restated Agreement of Limited Partnership of Williams Partners L.P., dated as of June 10, 2015 (filed on June 12, 2015 as Exhibit 3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
3.11
 
 
Amendment No. 6 to the First Amended and Restated Agreement of Limited Partnership of Williams Partners L.P., dated September 28, 2015 (filed on September 28, 2015 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
3.12
 
 
Composite Agreement of Limited Partnership of Williams Partners L.P. (filed on October 29, 2015 as Exhibit 3.12 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
3.13
 
 
Certificate of Formation of Chesapeake Midstream GP, L.L.C. (filed on February 16, 2010 as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905) and incorporated herein by reference).
 
 
 
 
 
3.14
 
 
Certificate of Amendment to Certificate of Formation of Chesapeake Midstream GP, L.L.C. (filed on July 30, 2012 as Exhibit 3.5 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
3.15
 
 
Certificate of Amendment to Certificate of Formation of Access Midstream Partners GP, L.L.C. (filed on February 3, 2015 as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.16
 
 
Composite Certificate of Formation of WPZ GP LLC (filed on February 25, 2015 as Exhibit 3.14 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.17
 
 
Seventh Amended and Restated Limited Liability Company Agreement of WPZ GP LLC (filed on February 2, 2015 as Exhibit 3.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.1
 
 
Indenture, dated as of January 11, 2012, by and among the Chesapeake Midstream Partners, L.P., CHKM Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 11, 2012 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.2
 
 
First Supplemental Indenture, dated as of January 7, 2013, by and among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on February 21, 2014 as Exhibit 4.5 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.3
 
 
Second Supplemental Indenture and Amendment - Subsidiary Guarantee, dated as of April 18, 2014 among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee filed on May 1, 2014 as Exhibit 4.4 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).



Exhibit
Number
 
 
 
Description
 
 
 
 
 
 
 
 
 
 
4.4
 
 
Third Supplemental Indenture among Williams Partners L.P., ACMP Finance Corp. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.5
 
 
Indenture, dated as of December 19, 2012, by and among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on December 19, 2012 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.6
 
 
First Supplemental Indenture, dated as of December 19, 2012, among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on December 19, 2012 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.7
 
 
Second Supplemental Indenture and Amendment - Subsidiary Guarantee, dated as of January 7, 2013, by among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on February 21, 2014 as Exhibit 4.9 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.8
 
 
Third Supplemental Indenture, dated as of March 7, 2014, among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 7, 2014 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.9
 
 
Third Supplemental Indenture and Amendment - Subsidiary Guarantee, dated as of April 18, 2014, among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on May 1, 2014 as Exhibit 4.3 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.10
 
 
Fifth Supplemental Indenture among Williams Partners L.P., ACMP Finance Corp. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.11
 
 
Certificate of Incorporation of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.5 to Pre-merger WPZ’s registration statement on Form S-3 (File No. 333-137562) and incorporated herein by reference).
 
 
 
 
 
4.12
 
 
Bylaws of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.6 to Pre-merger WPZ’s registration statement on Form S-3 (File No. 333-137562) and incorporated herein by reference).
 
 
 
 
 
4.13
 
 
Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.14
 
 
First Supplemental Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.2 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.15
 
 
Second Supplemental Indenture, dated as of November 17, 2011, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 18, 2011 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.16
 
 
Third Supplemental Indenture (including Form of 3.35% Senior Notes due 2022), dated as of August 14, 2012, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 14, 2012 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 



Exhibit
Number
 
 
 
Description
 
 
 
 
 
4.17
 
 
Fourth Supplemental Indenture, dated as of November 15, 2013, between Pre-merger WPZ and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 18, 2013 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.18
 
 
Fifth Supplemental Indenture, dated as of March 4, 2014, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 4, 2014 as Exhibit 4.1 Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.19
 
 
Sixth Supplemental Indenture, dated as of June 27, 2014, between Pre-merger WPZ and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on June 27, 2014 as Exhibit 4.1 to Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.20
 
 
Seventh Supplemental Indenture, dated as of February 2, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.4 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.21
 
 
Indenture, dated December 13, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York (filed on December 19, 2006 as Exhibit 4.1 to Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.22
 
 
First Supplemental Indenture, dated as of February 2, 2015, among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015, as Exhibit 4.6 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
4.23
 
 
Indenture, dated as of February 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.24
 
 
First Supplemental Indenture, dated as of February 2, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.5 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.25
 
 
Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank Trustee (filed on September 14, 1995 as Exhibit 4.1 to Northwest Pipeline GP’s registration statement on Form S-3 (File No. 033-62639) and incorporated herein by reference).
 
 
 
 
 
4.26
 
 
Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K (File. No. 001-07414), and incorporated herein by reference).
 
 
 
 
 
4.27
 
 
Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
 
 
 
 
 
4.28
 
 
Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K File No. 001-07414) and incorporated herein by reference).
 
 
 
 
 
4.29
 
 
Senior Indenture, dated as of July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s registration statement on Form S-3 (File No. 333-02155) and incorporated herein by reference).
 
 
 
 
 
4.30
 
 
Indenture, dated as of April 11, 2006, between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee with regard to Transcontinental Gas Pipe Line’s $200 million aggregate principal amount of 6.4% Senior Note due 2016 (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
 
 
 
 
 



Exhibit
Number
 
 
 
Description
 
 
 
 
 
4.31
 
 
Indenture, dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
 
 
 
 
 
4.32
 
 
Indenture, dated as of August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 12, 2011 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
 
 
 
 
 
4.33
 
 
Indenture, dated as of July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on July 16, 2012 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
 
 
 
 
 
4.34
 
 
Eighth Supplemental Indenture, dated as of March 3, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 3, 2015 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.35
 
 
Indenture, dated as of January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 22, 2016 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
10.1#
 
 
Williams Partners GP LLC Long-Term Incentive Plan (filed on August 26, 2005 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
10.2#
 
 
Amendment to the Williams Partners GP LLC Long-Term Incentive Plan, dated November 28, 2006 (filed on December 4, 2006 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
10.3#
 
 
Amendment No. 2 to the Williams Partners GP LLC Long-Term Incentive Plan, dated December 2, 2008 (filed on February 26, 2009, as Exhibit 10.4 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
10.4#
 
 
Chesapeake Midstream Long-Term Incentive Plan (filed on July 20, 2010 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905) and incorporated herein by reference).
 
 
 
 
 
10.5#
 
 
First Amendment to Access Midstream Long-Term Incentive Plan, dated effective as of July 1, 2014 (filed on July 2, 2014 as Exhibit 10.01 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.6#
 
 
Second Amendment to Williams Partners L.P. Long-Term Incentive Plan, dated effective as of February 2, 2015 (filed on February 25, 2015 as Exhibit 10.6 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.7
 
 
Amended and Restated Services Agreement, dated August 3, 2013, by and among Chesapeake Midstream Management, L.L.C., Chesapeake Operating Inc., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Partners, L.P., and Chesapeake MLP Operating, L.L.C. (filed on August 5, 2010 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.8
 
 
Compression Services Agreement, dated February 26, 2014 between EXLP Operating LLC and Access MLP Operating, L.L.C. (filed on April 30, 2014 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
10.9#
 
 
Form of Restricted Phantom Unit Award Agreement (filed on July 7, 2014 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 



Exhibit
Number
 
 
 
Description
 
 
 
 
 
10.10#
 
 
WPZ GP LLC Director Compensation Policy adopted December 11, 2014 (filed on February 25, 2015 as Exhibit 10.16 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.11#
 
 
WPZ GP LLC Director Compensation Policy adopted April 20, 2015 (filed on July 30, 2015 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.12
 
 
Form of Amended and Restated Commercial Paper Dealer Agreement, dated as of February 2, 2015, between Williams Partners L.P., as Issuer, and the Dealer party thereto (filed on February 3, 2015 as Exhibit 10.3 to Williams Partners L.P.’s Current Report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.13
 
 
Second Amended and Restated Credit Agreement dated as of February 2, 2015, between Williams Partners L.P., Northwest Pipeline LLC, Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on February 3, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.14
 
 
Credit Agreement dated as of February 3, 2015, between Williams Partners L.P., the lenders named therein, and Barclays Bank PLC as Administrative Agent (filed on February 3, 2015 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.15
 
 
Contractor Agreement by and between J. Mike Stice and WPZ GP LLC dated March 1, 2015 (filed on April 30, 2015 as Exhibit 10.5 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.16
 
 
First Amendment to Outstanding Restricted Phantom Unit Award Agreement for Williams Partners Long-Term Incentive Plan (filed on October 29, 2015 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.17
 
 
Credit Agreement dated as of August 26, 2015, among Williams Partners L.P., the lenders named therein, and Barclays Bank PLC as Administrative Agent (filed on August 28, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.18
 
 
Termination Agreement and Release, dated as of September 28, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P. and WPZ GP LLC (filed on September 28, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.19
 
 
Amendment No. 1 to Second Amended & Restated Credit Agreement dated December 18, 2015, between Williams Partners L.P., Northwest Pipeline LLC, Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on December 23, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.20
 
 
Credit Agreement dated as of December 23, 2015, between Williams Partners L.P., the lenders named therein, and Barclays Bank PLC as Administrative Agent (filed on December 23, 2015 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.21
 
 
Equity Distribution Agreement dated March 6, 2015, between Williams Partners L.P., WPZ GP LLC and Citigroup Global Markets Inc., Barclays Capital Inc., J.P. Morgan Securities LLC, UBS Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Scotia Capital (USA) Inc., Deutsche Bank Securities Inc., Morgan Stanley & Co. LLC, Mizuho Securities USA Inc. and Mitsubishi UFJ Securities (USA), Inc. (filed on March 6, 2015 as Exhibit 1.1 to Williams Partners L.P.’s current report on From 8-K (File No. 001-34831) and incorporated herein by reference). 

 
 
 
 
 



Exhibit
Number
 
 
 
Description
 
 
 
 
 
10.22*
 
 
Amendment to Equity Distribution Agreement dated June 17, 2015 between Williams Partners L.P., WPZ GP LLC and Citigroup Global Markets Inc., Barclays Capital Inc., J.P. Morgan Securities LLC, UBS Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Scotia Capital (USA) Inc., Deutsche Bank Securities Inc., Morgan Stanley & Co. LLC, Mizuho Securities USA Inc. and Mitsubishi UFJ Securities (USA), Inc.





 
 
 
 
 
10.23
 
 
Registration Rights Agreement, dated January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and each of the initial purchasers listed therein (filed on January 22, 2016 as Exhibit 10.1 to Williams Partners L.P.’s Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
12*
 
 
Computation of Ratio of Earnings to Fixed Charges.
 21*
 
 
List of subsidiaries of Williams Partners L.P.
 23.1*
 
 
Consent of Ernst & Young LLP.
 23.2*
 
 
Consent of Deloitte & Touche LLP
24*
 
 
Power of attorney.
 31.1*
 
 
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
 31.2*
 
 
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32**
 
 
Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.
101.INS*
 
 
XBRL Instance Document.
101.SCH*
 
 
XBRL Taxonomy Extension Schema.
101.CAL*
 
 
XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*
 
 
XBRL Taxonomy Extension Definition Linkbase.
101.LAB*
 
 
XBRL Taxonomy Extension Label Linkbase.
101.PRE*
 
 
XBRL Taxonomy Extension Presentation Linkbase.
___________________
*
Filed herewith.
 
 
**
Furnished herewith.
 
 
§
Pursuant to item 601(b) (2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.
 
 
#
Management contract or compensatory plan or arrangement.

Portions of this exhibit have been omitted pursuant to a request for confidential treatment. Such portions have been filed separately with the Securities and Exchange Commission.




SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

WILLIAMS PARTNERS L.P.
(Registrant)
By: WPZ GP LLC, its general partner
 
/s/ Ted T. Timmermans
Ted T. Timmermans
Vice President, Controller, and Chief Accounting
Officer (Duly Authorized Officer and Principal
    Accounting Officer)
Date: February 26, 2016
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
 
Title
 
Date
 
 
 
 
 
/s/ ALAN S. ARMSTRONG
 
Chief Executive Officer and
 
February 26, 2016
Alan S. Armstrong
 
Chairman of the Board (Principal
Executive Officer)
 
 
 
 
 
 
 
/s/ DONALD R. CHAPPEL
 
Chief Financial Officer and Director
 
February 26, 2016
Donald R. Chappel
 
(Principal Financial Officer)
 
 
 
 
 
 
 
/s/ TED T. TIMMERMANS
 
Vice President, Controller, and Chief
 
February 26, 2016
Ted T. Timmermans
 
Accounting Officer
(Principal Accounting Officer)
 
 
 
 
 
 
 
/s/ H. BRENT AUSTIN*
 
Director
 
February 26, 2016
H. Brent Austin
 
 
 
 
 
 
 
 
 
/s/ FRANCIS E BILLINGS*
 
Director
 
February 26, 2016
Francis E. Billings
 
 
 
 
 
 
 
 
 
/s/ PHIL L FREDRICKSON*
 
Director
 
February 26, 2016
Phil L. Fredrickson
 
 
 
 
 
 
 
 
 
/s/ RORY L. MILLER*
 
Director
 
February 26, 2016
Rory L. Miller
 
 
 
 
 
 
 
 
 
/s/ ALICE M. PETERSON*
 
Director
 
February 26, 2016
Alice M. Peterson
 
 
 
 
 
 
 
 
 
/s/ ROBERT S PURGASON*
 
Director
 
February 26, 2016
Robert S. Purgason
 
 
 
 
 
 
 
 
 
/s/ JAMES E. SCHEEL *
 
Director
 
February 26, 2016
James E. Scheel
 
 
 
 
 
 
 
 
 
*By:     /s/ Sarah C. Miller
 
 
 
February 26, 2016
Sarah C. Miller
Attorney-in-fact
 
 
 
 



EXHIBIT INDEX
Exhibit
Number
 
 
 
Description
 
 
 
 
 
2.1§
 
 
Agreement and Plan of Merger dated as of May 12, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May 13, 2015 as Exhibit 2.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
3.1
 
 
Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. (filed on February 16, 2010 as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905 and incorporated herein by reference).

 
 
 
 
 
3.2
 
 
Amendment to Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. (filed on July 30, 2012 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.3
 
 
Amendment to Certificate of Limited Partnership of Access Midstream Partners, L.P. (filed on February 3, 2015 as Exhibit 3.5 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.4
 
 
Composite Certificate of Limited Partnership of Williams Partners L.P. (filed on February 25, 2015 as Exhibit 3.4 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.5
 
 
First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P., dated August 3, 2010 (filed on August 5, 2010 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.6
 
 
Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. dated as of July 24, 2012 (filed on July 30, 2012 as Exhibit 3.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.7
 
 
Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of December 20, 2012 (filed on December 26, 2012 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
3.8
 
 
Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of January 29, 2015 (filed on February 3, 2015 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.9
 
 
Amendment No. 4 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of January 29, 2015 (filed on February 3, 2015 as Exhibit 3.4 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
3.10
 
 
Amendment No. 5 to the First Amended and Restated Agreement of Limited Partnership of Williams Partners L.P., dated as of June 10, 2015 (filed on June 12, 2015 as Exhibit 3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
3.11
 
 
Amendment No. 6 to the First Amended and Restated Agreement of Limited Partnership of Williams Partners L.P., dated September 28, 2015 (filed on September 28, 2015 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
3.12
 
 
Composite Agreement of Limited Partnership of Williams Partners L.P. (filed on October 29, 2015 as Exhibit 3.12 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
3.13
 
 
Certificate of Formation of Chesapeake Midstream GP, L.L.C. (filed on February 16, 2010 as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905) and incorporated herein by reference).
 
 
 
 
 



Exhibit
Number
 
 
 
Description
 
 
 
 
 
3.14
 
 
Certificate of Amendment to Certificate of Formation of Chesapeake Midstream GP, L.L.C. (filed on July 30, 2012 as Exhibit 3.5 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
3.15
 
 
Certificate of Amendment to Certificate of Formation of Access Midstream Partners GP, L.L.C. (filed on February 3, 2015 as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.16
 
 
Composite Certificate of Formation of WPZ GP LLC (filed on February 25, 2015 as Exhibit 3.14 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
3.17
 
 
Seventh Amended and Restated Limited Liability Company Agreement of WPZ GP LLC (filed on February 2, 2015 as Exhibit 3.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.1
 
 
Indenture, dated as of January 11, 2012, by and among the Chesapeake Midstream Partners, L.P., CHKM Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 11, 2012 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.2
 
 
First Supplemental Indenture, dated as of January 7, 2013, by and among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on February 21, 2014 as Exhibit 4.5 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.3
 
 
Second Supplemental Indenture and Amendment - Subsidiary Guarantee, dated as of April 18, 2014 among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee filed on May 1, 2014 as Exhibit 4.4 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.4
 
 
Third Supplemental Indenture among Williams Partners L.P., ACMP Finance Corp. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.5
 
 
Indenture, dated as of December 19, 2012, by and among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on December 19, 2012 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.6
 
 
First Supplemental Indenture, dated as of December 19, 2012, among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on December 19, 2012 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.7
 
 
Second Supplemental Indenture and Amendment - Subsidiary Guarantee, dated as of January 7, 2013, by among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on February 21, 2014 as Exhibit 4.9 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.8
 
 
Third Supplemental Indenture, dated as of March 7, 2014, among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 7, 2014 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.9
 
 
Third Supplemental Indenture and Amendment - Subsidiary Guarantee, dated as of April 18, 2014, among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on May 1, 2014 as Exhibit 4.3 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 



Exhibit
Number
 
 
 
Description
 
 
 
 
 
4.10
 
 
Fifth Supplemental Indenture among Williams Partners L.P., ACMP Finance Corp. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.11
 
 
Certificate of Incorporation of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.5 to Pre-merger WPZ’s registration statement on Form S-3 (File No. 333-137562) and incorporated herein by reference).
 
 
 
 
 
4.12
 
 
Bylaws of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.6 to Pre-merger WPZ’s registration statement on Form S-3 (File No. 333-137562) and incorporated herein by reference).
 
 
 
 
 
4.13
 
 
Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.14
 
 
First Supplemental Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.2 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.15
 
 
Second Supplemental Indenture, dated as of November 17, 2011, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 18, 2011 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.16
 
 
Third Supplemental Indenture (including Form of 3.35% Senior Notes due 2022), dated as of August 14, 2012, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 14, 2012 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.17
 
 
Fourth Supplemental Indenture, dated as of November 15, 2013, between Pre-merger WPZ and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 18, 2013 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.18
 
 
Fifth Supplemental Indenture, dated as of March 4, 2014, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 4, 2014 as Exhibit 4.1 Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.19
 
 
Sixth Supplemental Indenture, dated as of June 27, 2014, between Pre-merger WPZ and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on June 27, 2014 as Exhibit 4.1 to Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.20
 
 
Seventh Supplemental Indenture, dated as of February 2, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.4 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.21
 
 
Indenture, dated December 13, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York (filed on December 19, 2006 as Exhibit 4.1 to Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.22
 
 
First Supplemental Indenture, dated as of February 2, 2015, among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015, as Exhibit 4.6 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 



Exhibit
Number
 
 
 
Description
 
 
 
 
 
4.23
 
 
Indenture, dated as of February 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
4.24
 
 
First Supplemental Indenture, dated as of February 2, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.5 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.25
 
 
Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank Trustee (filed on September 14, 1995 as Exhibit 4.1 to Northwest Pipeline GP’s registration statement on Form S-3 (File No. 033-62639) and incorporated herein by reference).
 
 
 
 
 
4.26
 
 
Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K (File. No. 001-07414), and incorporated herein by reference).
 
 
 
 
 
4.27
 
 
Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
 
 
 
 
 
4.28
 
 
Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K File No. 001-07414) and incorporated herein by reference).
 
 
 
 
 
4.29
 
 
Senior Indenture, dated as of July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s registration statement on Form S-3 (File No. 333-02155) and incorporated herein by reference).
 
 
 
 
 
4.30
 
 
Indenture, dated as of April 11, 2006, between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee with regard to Transcontinental Gas Pipe Line’s $200 million aggregate principal amount of 6.4% Senior Note due 2016 (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
 
 
 
 
 
4.31
 
 
Indenture, dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
 
 
 
 
 
4.32
 
 
Indenture, dated as of August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 12, 2011 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
 
 
 
 
 
4.33
 
 
Indenture, dated as of July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on July 16, 2012 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
 
 
 
 
 
4.34
 
 
Eighth Supplemental Indenture, dated as of March 3, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 3, 2015 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
4.35
 
 
Indenture, dated as of January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 22, 2016 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
10.1#
 
 
Williams Partners GP LLC Long-Term Incentive Plan (filed on August 26, 2005 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 



Exhibit
Number
 
 
 
Description
 
 
 
 
 
10.2#
 
 
Amendment to the Williams Partners GP LLC Long-Term Incentive Plan, dated November 28, 2006 (filed on December 4, 2006 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
10.3#
 
 
Amendment No. 2 to the Williams Partners GP LLC Long-Term Incentive Plan, dated December 2, 2008 (filed on February 26, 2009, as Exhibit 10.4 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-32599) and incorporated herein by reference).
 
 
 
 
 
10.4#
 
 
Chesapeake Midstream Long-Term Incentive Plan (filed on July 20, 2010 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905) and incorporated herein by reference).
 
 
 
 
 
10.5#
 
 
First Amendment to Access Midstream Long-Term Incentive Plan, dated effective as of July 1, 2014 (filed on July 2, 2014 as Exhibit 10.01 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.6#
 
 
Second Amendment to Williams Partners L.P. Long-Term Incentive Plan, dated effective as of February 2, 2015 (filed on February 25, 2015 as Exhibit 10.6 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.7
 
 
Amended and Restated Services Agreement, dated August 3, 2013, by and among Chesapeake Midstream Management, L.L.C., Chesapeake Operating Inc., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Partners, L.P., and Chesapeake MLP Operating, L.L.C. (filed on August 5, 2010 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.8
 
 
Compression Services Agreement, dated February 26, 2014 between EXLP Operating LLC and Access MLP Operating, L.L.C. (filed on April 30, 2014 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).

 
 
 
 
 
10.9#
 
 
Form of Restricted Phantom Unit Award Agreement (filed on July 7, 2014 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.10#
 
 
WPZ GP LLC Director Compensation Policy adopted December 11, 2014 (filed on February 25, 2015 as Exhibit 10.16 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.11#
 
 
WPZ GP LLC Director Compensation Policy adopted April 20, 2015 (filed on July 30, 2015 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
10.12
 
 
Form of Amended and Restated Commercial Paper Dealer Agreement, dated as of February 2, 2015, between Williams Partners L.P., as Issuer, and the Dealer party thereto (filed on February 3, 2015 as Exhibit 10.3 to Williams Partners L.P.’s Current Report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.13
 
 
Second Amended and Restated Credit Agreement dated as of February 2, 2015, between Williams Partners L.P., Northwest Pipeline LLC, Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on February 3, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.14
 
 
Credit Agreement dated as of February 3, 2015, between Williams Partners L.P., the lenders named therein, and Barclays Bank PLC as Administrative Agent (filed on February 3, 2015 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.15
 
 
Contractor Agreement by and between J. Mike Stice and WPZ GP LLC dated March 1, 2015 (filed on April 30, 2015 as Exhibit 10.5 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 



Exhibit
Number
 
 
 
Description
 
 
 
 
 
10.16
 
 
First Amendment to Outstanding Restricted Phantom Unit Award Agreement for Williams Partners Long-Term Incentive Plan (filed on October 29, 2015 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.17
 
 
Credit Agreement dated as of August 26, 2015, among Williams Partners L.P., the lenders named therein, and Barclays Bank PLC as Administrative Agent (filed on August 28, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.18
 
 
Termination Agreement and Release, dated as of September 28, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P. and WPZ GP LLC (filed on September 28, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.19
 
 
Amendment No. 1 to Second Amended & Restated Credit Agreement dated December 18, 2015, between Williams Partners L.P., Northwest Pipeline LLC, Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on December 23, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.20
 
 
Credit Agreement dated as of December 23, 2015, between Williams Partners L.P., the lenders named therein, and Barclays Bank PLC as Administrative Agent (filed on December 23, 2015 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
10.21
 
 
Equity Distribution Agreement dated March 6, 2015, between Williams Partners L.P., WPZ GP LLC and Citigroup Global Markets Inc., Barclays Capital Inc., J.P. Morgan Securities LLC, UBS Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Scotia Capital (USA) Inc., Deutsche Bank Securities Inc., Morgan Stanley & Co. LLC, Mizuho Securities USA Inc. and Mitsubishi UFJ Securities (USA), Inc. (filed on March 6, 2015 as Exhibit 1.1 to Williams Partners L.P.’s current report on From 8-K (File No. 001-34831) and incorporated herein by reference). 
 
 
 
 
 
10.22*
 
 
Amendment to Equity Distribution Agreement dated June 17, 2015 between Williams Partners L.P., WPZ GP LLC and Citigroup Global Markets Inc., Barclays Capital Inc., J.P. Morgan Securities LLC, UBS Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Scotia Capital (USA) Inc., Deutsche Bank Securities Inc., Morgan Stanley & Co. LLC, Mizuho Securities USA Inc. and Mitsubishi UFJ Securities (USA), Inc.
 
 
 
 
 
10.23
 
 
Registration Rights Agreement, dated January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and each of the initial purchasers listed therein (filed on January 22, 2016 as Exhibit 10.1 to Williams Partners L.P.’s Form 8-K (File No. 001-34831) and incorporated herein by reference).
 
 
 
 
 
12*
 
 
Computation of Ratio of Earnings to Fixed Charges.
 21*
 
 
List of subsidiaries of Williams Partners L.P.
 23.1*
 
 
Consent of Ernst & Young LLP.
 23.2*
 
 
Consent of Deloitte & Touche LLP
24*
 
 
Power of attorney.
 31.1*
 
 
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
 31.2*
 
 
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32**
 
 
Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.
101.INS*
 
 
XBRL Instance Document.
101.SCH*
 
 
XBRL Taxonomy Extension Schema.



Exhibit
Number
 
 
 
Description
 
 
 
 
 
101.CAL*
 
 
XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*
 
 
XBRL Taxonomy Extension Definition Linkbase.
101.LAB*
 
 
XBRL Taxonomy Extension Label Linkbase.
101.PRE*
 
 
XBRL Taxonomy Extension Presentation Linkbase.
___________________
*
Filed herewith.
 
 
**
Furnished herewith.
 
 
§
Pursuant to item 601(b) (2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.
 
 
#
Management contract or compensatory plan or arrangement.

Portions of this exhibit have been omitted pursuant to a request for confidential treatment. Such portions have been filed separately with the Securities and Exchange Commission.