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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Williams Partners, L.P. Common Units Representing Limited Partner Interests (delisted) | NYSE:WPZ | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 47.37 | 0 | 01:00:00 |
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(Mark One)
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2016
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OR
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
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For the transition period from
to
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Delaware
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20-2485124
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(State or Other Jurisdiction of Incorporation or Organization)
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(I.R.S. Employer Identification No.)
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One Williams Center, Tulsa, Oklahoma
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74172-0172
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(Address of Principal Executive Offices)
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(Zip Code)
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Units
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New York Stock Exchange
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Large accelerated filer
þ
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Accelerated filer
¨
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Non-accelerated filer
¨
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Smaller reporting company
¨
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(Do not check if a smaller reporting company)
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Page
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PART I
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Item 1.
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Item 1A.
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Item 1B.
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Item 2.
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Item 3.
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Item 4.
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PART II
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Item 5.
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Item 6.
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Item 7.
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Item 7A.
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Item 8.
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Item 9.
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Item 9A.
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Item 9B.
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PART III
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Item 10.
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Item 11.
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Item 12.
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Item 13.
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Item 14.
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PART IV
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Item 15.
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•
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The NGL and natural gas marketing business, certain storage and fractionation operations, and our equity-method investment in OPPL are managed within the West reporting segment;
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•
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Certain pipelines in the Gulf region are managed within the Atlantic-Gulf reporting segment;
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•
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Our equity-method investment in Aux Sable is managed within the Northeast G&P reporting segment.
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Northeast G&P —
this segment includes our natural gas gathering and processing, compression, 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 66 percent interest in Cardinal (a consolidated entity), 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 41 percent equity-method investment in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
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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 assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated entity), which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, 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.
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•
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West
— this segment includes our interstate natural gas pipeline, Northwest Pipeline, and natural gas gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, as well as 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. This reporting 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, a 50 percent equity-method investment in the Delaware basin gas gathering system in the Mid-Continent region, and a 50 percent equity-method investment in OPPL.
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•
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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. Prior to September 2016, this reporting segment also included an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility which were subsequently sold.
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Natural Gas Gathering Assets
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Inlet
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Pipeline
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Capacity
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Ownership
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Location
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Miles
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(Bcf/d)
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Interest
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Supply Basins
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Ohio Valley
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West Virginia & Pennsylvania
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210
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0.8
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100%
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Appalachian
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Susquehanna Supply Hub
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Pennsylvania & New York
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399
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2.9
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100%
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Appalachian
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Cardinal (1)
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Ohio
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352
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1.0
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66%
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Appalachian
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Flint
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Ohio
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33
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0.2
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100%
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Appalachian
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Marcellus South (2)
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West Virginia & Pennsylvania
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41
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0.1
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100%
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Appalachian
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(1)
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Statistics reflect 100 percent of the assets from our 66 percent ownership of Cardinal gathering system.
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(2)
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Statistics reflect 100 percent of the Beaver Creek assets from our 67 percent ownership in the Marcellus South gathering system.
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Natural Gas Processing Facilities
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NGL
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Inlet
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Production
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Capacity
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Capacity
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Ownership
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Location
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(Bcf/d)
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(Mbbls/d)
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Interest
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Supply Basins
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Fort Beeler
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Marshall County, WV
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0.5
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62
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100%
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Appalachian
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Oak Grove
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Marshall County, WV
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0.2
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25
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100%
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Appalachian
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2016
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2015
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2014
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Volumes: (1)
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Gathering (Bcf/d)
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3.21
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3.10
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3.73
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Plant inlet natural gas volumes (Bcf/d)
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0.33
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0.34
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0.27
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NGL production volumes (Mbbls/d) (2)
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32
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23
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12
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(1)
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Excludes volumes associated with equity-method investments.
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(2)
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Annual average Mbbls/d.
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Natural Gas Gathering Assets
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Inlet
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Pipeline
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Capacity
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Ownership
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Location
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Miles
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(Bcf/d)
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Interest
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Supply Basins
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Canyon Chief, including Blind Faith and Gulfstar extensions
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Deepwater Gulf of Mexico
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156
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0.5
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100%
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Eastern Gulf of Mexico
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Other Eastern Gulf
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Offshore shelf and other
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46
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0.2
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100%
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Eastern Gulf of Mexico
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Seahawk
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Deepwater Gulf of Mexico
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115
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0.4
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100%
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Western Gulf of Mexico
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Perdido Norte
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Deepwater Gulf of Mexico
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105
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0.3
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100%
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Western Gulf of Mexico
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Other Western Gulf
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Offshore shelf and other
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120
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0.9
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100%
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Western Gulf of Mexico
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Natural Gas Processing Facilities
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NGL
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Inlet
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Production
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Capacity
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Capacity
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Ownership
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Location
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(Bcf/d)
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(Mbbls/d)
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Interest
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Supply Basins
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Markham
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Markham, TX
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0.5
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45
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100%
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Western Gulf of Mexico
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Mobile Bay
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Coden, AL
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0.7
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30
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100%
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Eastern Gulf of Mexico
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Crude Oil Pipelines
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Pipeline
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Capacity
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Ownership
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Miles
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(Mbbls/d)
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Interest
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Supply Basins
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Mountaineer, including Blind Faith and Gulfstar extensions
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172
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150
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100%
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Eastern Gulf of Mexico
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BANJO
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57
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90
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100%
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Western Gulf of Mexico
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Alpine
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96
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85
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100%
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Western Gulf of Mexico
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Perdido Norte
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74
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150
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100%
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Western Gulf of Mexico
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Production Handling Platforms
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Crude/NGL
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Gas Inlet
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Handling
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Capacity
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Capacity
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Ownership
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(MMcf/d)
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(Mbbls/d)
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Interest
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Supply Basins
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Devils Tower
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210
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60
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100%
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Eastern Gulf of Mexico
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Gulfstar I FPS (1)
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172
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80
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51%
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Eastern Gulf of Mexico
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(1)
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Statistics reflect 100 percent of the assets from our 51 percent interest in Gulfstar One.
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2016
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2015
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2014
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Volumes: (1)
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Interstate natural gas pipeline throughput (Tbtu)
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3,503
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3,373
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3,455
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Gathering (Bcf/d)
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0.41
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0.34
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0.28
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Plant inlet natural gas (Bcf/d)
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0.72
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0.66
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0.67
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NGL production (Mbbls/d) (2)
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41
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34
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37
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NGL equity sales (Mbbls/d) (2)
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13
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6
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5
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Crude oil transportation (Mbbls/d) (2)
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113
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126
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105
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(1)
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Excludes volumes associated with equity-method investments.
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(2)
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Annual average Mbbls/d.
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Natural Gas Gathering Assets
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Inlet
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Pipeline
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Capacity
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Ownership
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Location
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Miles
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(Bcf/d)
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Interest
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Supply Basins/Shale Formations
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Four Corners
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Colorado & New Mexico
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3,743
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1.8
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100%
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San Juan
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Wamsutter
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Wyoming
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1,973
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0.6
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100%
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Wamsutter
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Southwest Wyoming
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Wyoming
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1,614
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0.5
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100%
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Southwest Wyoming
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Piceance
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Colorado
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336
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1.5
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(1)
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Piceance
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Niobrara
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Wyoming
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184
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0.2
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(2)
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Powder River
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Barnett Shale
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Texas
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858
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0.9
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100%
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Barnett Shale
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Eagle Ford Shale
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Texas
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1,010
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0.7
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100%
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Eagle Ford Shale
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Haynesville Shale
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Louisiana
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598
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1.7
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100%
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Haynesville Shale
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Permian
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Texas
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346
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0.1
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100%
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Permian
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Mid-Continent
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Oklahoma & Kansas
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2,112
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0.9
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100%
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Miss-Lime, Granite Wash, Colony Wash
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(1)
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Includes our 60 percent ownership of a gathering system in the Ryan Gulch area with 140 miles of pipeline and 0.2 Bcf/d of inlet capacity, and our 67 percent ownership of a gathering system at Allen Point with 8 miles of pipeline and 0.1 Bcf/d of inlet capacity. We operate both systems. We own and operate 100 percent of the balance of the Piceance gathering assets.
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(2)
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Includes our 50 percent ownership of the Jackalope gathering system.
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Natural Gas Processing Facilities
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NGL
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Inlet
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Production
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Capacity
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Capacity
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Ownership
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Location
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(Bcf/d)
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(Mbbls/d)
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Interest
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Supply Basins
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Echo Springs
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Echo Springs, WY
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0.7
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58
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100%
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Wamsutter
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Opal
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Opal, WY
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1.1
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47
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100%
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Southwest Wyoming
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Bucking Horse (1)
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Converse County, WY
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0.1
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7
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50%
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Powder River
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Willow Creek
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Rio Blanco County, CO
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0.5
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30
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100%
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Piceance
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Parachute
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Garfield County, CO
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1.1
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6
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100%
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Piceance
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Ignacio
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Ignacio, CO
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0.5
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29
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100%
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San Juan
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Kutz
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Bloomfield, NM
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0.2
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12
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100%
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San Juan
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(1)
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Statistics reflect 100 percent of the assets from our 50 percent ownership of Bucking Horse gas processing facility.
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2016
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2015
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2014
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|||
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Volumes:
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|||
Interstate natural gas pipeline throughput (Tbtu)
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727
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763
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687
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Gathering (Bcf/d)
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4.62
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4.90
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4.90
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Plant inlet natural gas (Bcf/d)
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2.45
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2.52
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2.89
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NGL production (Mbbls/d) (1)
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78
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74
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79
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NGL equity sales (Mbbls/d) (1)
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28
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21
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22
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(1)
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Annual average Mbbls/d.
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2016
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2015
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2014
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|||
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Volumes:
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|||
Geismar ethylene sales (millions of pounds)
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1,638
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1,066
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-
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Canadian propylene sales (millions of pounds)
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87
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161
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143
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Canadian NGL sales (millions of gallons)
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141
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284
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218
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•
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Ethane, primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic building blocks for plastics;
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•
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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;
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•
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Normal butane, isobutane and natural gasoline, primarily used by the refining industry as blending stocks for motor gasoline or as a petrochemical feedstock.
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•
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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, 2016
, 69 percent of the domestic NGL production volumes were under fee-based contracts.
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•
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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, 2016
, 26 percent of the domestic NGL production volumes were under keep-whole contracts.
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•
|
Percent-of-Liquids: Under percent-of-liquids processing contracts, we (1) process natural gas produced by customers, (2) deliver to customers an agreed-upon percentage of the extracted NGLs, (3) retain a portion of the extracted NGLs as compensation for our services, and (4) deliver natural gas to customers at the plant outlet. Under this type of contract, we are not required to replace the Btu content of the retained NGLs that were extracted during processing, and are therefore only exposed to NGL price movements. NGLs we retain in connection with this type of processing agreement are also referred to as our equity NGL production. For the year ended
December 31, 2016
, 5 percent of the domestic NGL production volumes were under percent-of-liquids contracts.
|
•
|
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.
|
|
Central
|
|
Northeast
G&P |
|
Atlantic-
Gulf |
|
West
|
|
Total
|
||||||||||
|
(Millions)
|
||||||||||||||||||
2016
|
|||||||||||||||||||
Service:
|
|
|
|
|
|
|
|
|
|
||||||||||
Regulated natural gas transportation and storage
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,527
|
|
|
$
|
474
|
|
|
$
|
2,001
|
|
Gathering, processing, and production handling
|
1,178
|
|
|
693
|
|
|
317
|
|
|
541
|
|
|
2,729
|
|
|||||
2015
|
|||||||||||||||||||
Service:
|
|
|
|
|
|
|
|
|
|
||||||||||
Regulated natural gas transportation and storage
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,465
|
|
|
$
|
473
|
|
|
$
|
1,938
|
|
Gathering, processing, and production handling
|
1,224
|
|
|
700
|
|
|
319
|
|
|
561
|
|
|
2,804
|
|
|||||
2014
|
|||||||||||||||||||
Service:
|
|
|
|
|
|
|
|
|
|
||||||||||
Regulated natural gas transportation and storage
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,311
|
|
|
$
|
470
|
|
|
$
|
1,781
|
|
Gathering, processing, and production handling
|
666
|
|
|
493
|
|
|
119
|
|
|
560
|
|
|
1,838
|
|
•
|
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.
|
•
|
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.
|
•
|
Levels of cash distributions with respect to limited partner interests;
|
•
|
Our and our affiliates’ 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.
|
•
|
Whether we will produce sufficient cash flows to provide the level of cash distributions that Williams expects;
|
•
|
Whether we elect to pay expected levels of cash distributions;
|
•
|
Whether we will be able to effectively execute our financing plan including the receipt of anticipated levels of proceeds from planned asset sales;
|
•
|
Whether Williams will be able to effectively manage the transition in its board of directors and management as well as successfully execute its business restructuring;
|
•
|
Availability of supplies, including lower than anticipated volumes from third parties served by our midstream business, and market demand;
|
•
|
Volatility of pricing including the effect of lower than anticipated energy commodity prices and margins;
|
•
|
Inflation, interest 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 timely execute our capital projects and other investment opportunities in accordance with our forecasted capital expenditures budget;
|
•
|
Our ability to successfully expand our facilities and operations;
|
•
|
Development of alternative energy sources;
|
•
|
Availability of adequate insurance coverage and the impact of operational and developmental hazards and unforeseen interruptions;
|
•
|
The impact of existing and future laws, regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain permits and achieve favorable rate proceeding outcomes;
|
•
|
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 and physical damage to our facilities;
|
•
|
Acts of terrorism, including cybersecurity threats, and related disruptions;
|
•
|
Additional risks described in our filings with the Securities and Exchange Commission (SEC).
|
•
|
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.
|
•
|
Changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings, and cash flow relating to potential investment targets, resulting in outcomes which are materially different than anticipated;
|
•
|
We could be required to contribute additional capital to support acquired businesses or assets;
|
•
|
We may assume liabilities that were not disclosed to us, that exceed our estimates and for which contractual protections are either unavailable or prove inadequate;
|
•
|
Acquisitions could disrupt our ongoing business, distract management, divert financial and operational resources from existing operations and make it difficult to maintain our current business standards, controls, and procedures;
|
•
|
Acquisitions and capital projects may require substantial new capital, including by the issuance of debt or equity, and we may not be able to access capital markets or obtain acceptable terms.
|
•
|
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.
|
•
|
The level of existing and new competition in our businesses or from alternative fuel sources, such as electricity, coal, fuel oils, or nuclear energy;
|
•
|
Natural gas, NGL, and olefins prices, demand, availability, and margins in our markets. Higher prices for energy commodities related to our businesses could result in a decline in the demand for those commodities and, therefore, in customer contracts or throughput on our pipeline systems. Also, lower energy commodity prices could negatively impact our ability to maintain or achieve favorable contractual terms, including pricing, and could also result in a decline in the production of energy commodities resulting in reduced customer contracts, supply contracts, and throughput on our pipeline systems;
|
•
|
General economic, financial markets, and industry conditions;
|
•
|
The effects of regulation on us, our customers, and our contracting practices;
|
•
|
Our ability to understand our customers’ expectations, efficiently and reliably deliver high quality services and effectively manage customer relationships. The results of these efforts will impact our reputation and positioning in the market.
|
•
|
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;
|
•
|
We have limited ability to influence or control certain day to day activities affecting the operations.
|
•
|
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.
|
•
|
Transportation and sale for resale of natural gas in interstate commerce;
|
•
|
Rates, operating terms, types of services, and conditions of service;
|
•
|
Certification and construction of new interstate pipelines and storage facilities;
|
•
|
Acquisition, extension, disposition, or abandonment of existing interstate pipelines and storage facilities;
|
•
|
Accounts and records;
|
•
|
Depreciation and amortization policies;
|
•
|
Relationships with affiliated companies who are involved in marketing functions of the natural gas business;
|
•
|
Market manipulation in connection with interstate sales, purchases, or transportation of natural gas.
|
•
|
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.
|
•
|
Neither our partnership agreement nor any other agreement requires Williams 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, in resolving conflicts of interest.
|
•
|
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 74 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.
|
•
|
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.
|
•
|
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 85 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.
|
•
|
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 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.
|
•
|
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.
|
•
|
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.
|
|
High
|
|
Low
|
|
Cash Distribution
per Unit (1)
|
2016
|
|
|
|
|
|
First Quarter
|
$28.66
|
|
$12.69
|
|
$0.85
|
Second Quarter
|
35.36
|
|
19.04
|
|
0.85
|
Third Quarter
|
40.36
|
|
33.17
|
|
0.85
|
Fourth Quarter
|
38.49
|
|
32.93
|
|
0.85
|
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
|
(1)
|
Represents cash distributions attributable to the quarter and declared and paid within 45 days after quarter end.
|
•
|
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;
|
•
|
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 provided that, at the time incurred, the borrower’s intent is to repay such borrowings within 12 months from sources other than working capital borrowings.
|
•
|
First, 98 percent to all common unitholders, pro rata, and 2 percent to our general partner, until each outstanding unit had received the minimum quarterly distribution for that quarter;
|
•
|
Thereafter, cash in excess of the minimum quarterly distributions was distributed to the common unitholders and the general partner based on the incentive percentages 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
|
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
|
(Millions, except per-unit amounts)
|
||||||||||||||||||
Revenues (1)
|
|
$
|
7,491
|
|
|
$
|
7,331
|
|
|
$
|
7,409
|
|
|
$
|
6,835
|
|
|
$
|
7,471
|
|
Net income (loss) (1) (2)
|
|
519
|
|
|
(1,358
|
)
|
|
1,284
|
|
|
1,119
|
|
|
1,291
|
|
|||||
Net income (loss) attributable to controlling interests (1) (2)
|
|
431
|
|
|
(1,449
|
)
|
|
1,188
|
|
|
1,116
|
|
|
1,291
|
|
|||||
Net income (loss) per common unit (1) (2)
|
|
(.17
|
)
|
|
(3.27
|
)
|
|
.99
|
|
|
1.76
|
|
|
2.30
|
|
|||||
Total assets at December 31 (1)
|
|
46,265
|
|
|
47,870
|
|
|
49,248
|
|
|
23,513
|
|
|
20,623
|
|
|||||
Commercial paper and long-term debt due within one year at December 31 (3)
|
|
878
|
|
|
675
|
|
|
802
|
|
|
225
|
|
|
—
|
|
|||||
Long-term debt at December 31 (1)
|
|
17,685
|
|
|
19,001
|
|
|
16,252
|
|
|
8,999
|
|
|
8,383
|
|
|||||
Total equity at December 31 (1)
|
|
23,203
|
|
|
24,606
|
|
|
28,685
|
|
|
11,567
|
|
|
9,691
|
|
|||||
Cash distributions declared per common unit
|
|
3.400
|
|
|
3.400
|
|
|
3.642
|
|
|
3.415
|
|
|
3.140
|
|
(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)
|
Net income (loss) for 2016 includes a $
457 million
impairment of certain assets and a $
430 million
impairment of certain equity-method investments. Net income (loss) for 2015 includes a $1.4 billion impairment of certain equity-method investments and a $1.1 billion impairment of goodwill.
|
(3)
|
The increases in 2014 and 2013 reflect borrowings under our commercial paper program, which was initiated in 2013.
|
•
|
Central 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 (DBJV) in the Mid-Continent region.
|
•
|
Northeast G&P is comprised of midstream gathering and processing businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia, and the Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal (a consolidated entity), a 69 percent equity-method investment in Laurel Mountain and a 58 percent equity-method investment in Caiman II. Northeast G&P also includes a 62 percent equity-method investment in UEOM and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 41 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
|
•
|
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, (see Geismar Olefins Facility Monetization below), 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 at Redwater, Alberta. In September 2016, these Canadian operations were sold. (See
Note 3 – Divestiture
of Notes to Consolidated Financial Statements.) 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.
|
•
|
The NGL and natural gas marketing business, certain storage and fractionation operations, and our equity-method investment in OPPL are managed within the West reporting segment;
|
•
|
Certain pipelines in the Gulf region are managed within the Atlantic-Gulf reporting segment;
|
•
|
Our equity-method investment in Aux Sable is managed within the Northeast G&P reporting segment.
|
|
•
|
Opposition to infrastructure projects, including the risk of delay in permits needed for our projects;
|
•
|
Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices and margins;
|
•
|
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.
|
|
Years Ended December 31,
|
||||||||||||||||||||||
|
2016
|
|
$ Change from 2015*
|
|
% Change from 2015*
|
|
2015
|
|
$ Change from 2014*
|
|
% Change from 2014*
|
|
2014
|
||||||||||
|
(Millions)
|
||||||||||||||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Service revenues
|
$
|
5,173
|
|
|
+38
|
|
|
+1
|
%
|
|
$
|
5,135
|
|
|
+1,247
|
|
|
+32
|
%
|
|
$
|
3,888
|
|
Product sales
|
2,318
|
|
|
+122
|
|
|
+6
|
%
|
|
2,196
|
|
|
-1,325
|
|
|
-38
|
%
|
|
3,521
|
|
|||
Total revenues
|
7,491
|
|
|
|
|
|
|
7,331
|
|
|
|
|
|
|
7,409
|
|
|||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Product costs
|
1,728
|
|
|
+51
|
|
|
+3
|
%
|
|
1,779
|
|
|
+1,237
|
|
|
+41
|
%
|
|
3,016
|
|
|||
Operating and maintenance expenses
|
1,548
|
|
|
+77
|
|
|
+5
|
%
|
|
1,625
|
|
|
-348
|
|
|
-27
|
%
|
|
1,277
|
|
|||
Depreciation and amortization expenses
|
1,720
|
|
|
-18
|
|
|
-1
|
%
|
|
1,702
|
|
|
-551
|
|
|
-48
|
%
|
|
1,151
|
|
|||
Selling, general, and administrative expenses
|
630
|
|
|
+54
|
|
|
+8
|
%
|
|
684
|
|
|
-51
|
|
|
-8
|
%
|
|
633
|
|
|||
Impairment of goodwill
|
—
|
|
|
+1,098
|
|
|
+100
|
%
|
|
1,098
|
|
|
-1,098
|
|
|
NM
|
|
|
—
|
|
|||
Impairment of certain assets
|
457
|
|
|
-312
|
|
|
NM
|
|
|
145
|
|
|
-93
|
|
|
-179
|
%
|
|
52
|
|
|||
Net insurance recoveries – Geismar Incident
|
(7
|
)
|
|
-119
|
|
|
-94
|
%
|
|
(126
|
)
|
|
-106
|
|
|
-46
|
%
|
|
(232
|
)
|
|||
Other (income) expense – net
|
118
|
|
|
-77
|
|
|
-188
|
%
|
|
41
|
|
|
-138
|
|
|
NM
|
|
|
(97
|
)
|
|||
Total costs and expenses
|
6,194
|
|
|
|
|
|
|
6,948
|
|
|
|
|
|
|
5,800
|
|
|||||||
Operating income (loss)
|
1,297
|
|
|
|
|
|
|
383
|
|
|
|
|
|
|
1,609
|
|
|||||||
Equity earnings (losses)
|
397
|
|
|
+62
|
|
|
+19
|
%
|
|
335
|
|
|
+107
|
|
|
+47
|
%
|
|
228
|
|
|||
Impairment of equity-method investments
|
(430
|
)
|
|
+929
|
|
|
+68
|
%
|
|
(1,359
|
)
|
|
-1,359
|
|
|
NM
|
|
|
—
|
|
|||
Other investing income (loss) – net
|
29
|
|
|
+27
|
|
|
NM
|
|
|
2
|
|
|
—
|
|
|
—
|
%
|
|
2
|
|
|||
Interest expense
|
(916
|
)
|
|
-105
|
|
|
-13
|
%
|
|
(811
|
)
|
|
-249
|
|
|
-44
|
%
|
|
(562
|
)
|
|||
Other income (expense) – net
|
62
|
|
|
-31
|
|
|
-33
|
%
|
|
93
|
|
|
+57
|
|
|
+158
|
%
|
|
36
|
|
|||
Income (loss) before income taxes
|
439
|
|
|
|
|
|
|
(1,357
|
)
|
|
|
|
|
|
1,313
|
|
|||||||
Provision (benefit) for income taxes
|
(80
|
)
|
|
+81
|
|
|
NM
|
|
|
1
|
|
|
+28
|
|
|
+97
|
%
|
|
29
|
|
|||
Net income (loss)
|
519
|
|
|
|
|
|
|
(1,358
|
)
|
|
|
|
|
|
1,284
|
|
|||||||
Less: Net income attributable to noncontrolling interests
|
88
|
|
|
+3
|
|
|
+3
|
%
|
|
91
|
|
|
+5
|
|
|
+5
|
%
|
|
96
|
|
|||
Net income (loss) attributable to controlling interests
|
$
|
431
|
|
|
|
|
|
|
$
|
(1,449
|
)
|
|
|
|
|
|
$
|
1,188
|
|
*
|
+ = 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.
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Service revenues
|
$
|
1,241
|
|
|
$
|
1,287
|
|
|
$
|
678
|
|
|
|
|
|
|
|
||||||
Segment costs and expenses
|
(387
|
)
|
|
(472
|
)
|
|
(272
|
)
|
|||
Impairments of certain assets
|
(95
|
)
|
|
(11
|
)
|
|
(12
|
)
|
|||
Proportional Modified EBITDA of equity-method investments
|
48
|
|
|
36
|
|
|
25
|
|
|||
Central Modified EBITDA
|
$
|
807
|
|
|
$
|
840
|
|
|
$
|
419
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Service revenues
|
$
|
838
|
|
|
$
|
810
|
|
|
$
|
550
|
|
Product sales
|
163
|
|
|
127
|
|
|
230
|
|
|||
Segment revenues
|
1,001
|
|
|
937
|
|
|
780
|
|
|||
|
|
|
|
|
|
||||||
Product costs
|
(159
|
)
|
|
(121
|
)
|
|
(221
|
)
|
|||
Other segment costs and expenses
|
(351
|
)
|
|
(380
|
)
|
|
(109
|
)
|
|||
Impairment of certain assets
|
(13
|
)
|
|
(32
|
)
|
|
(30
|
)
|
|||
Proportional Modified EBITDA of equity-method investments
|
362
|
|
|
349
|
|
|
198
|
|
|||
Northeast G&P Modified EBITDA
|
$
|
840
|
|
|
$
|
753
|
|
|
$
|
618
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Service revenues
|
$
|
1,952
|
|
|
$
|
1,881
|
|
|
$
|
1,501
|
|
Product sales
|
449
|
|
|
463
|
|
|
853
|
|
|||
Segment revenues
|
2,401
|
|
|
2,344
|
|
|
2,354
|
|
|||
|
|
|
|
|
|
||||||
Product costs
|
(405
|
)
|
|
(434
|
)
|
|
(791
|
)
|
|||
Other segment costs and expenses
|
(682
|
)
|
|
(639
|
)
|
|
(639
|
)
|
|||
Impairment of certain assets
|
(1
|
)
|
|
(5
|
)
|
|
(10
|
)
|
|||
Proportional Modified EBITDA of equity-method investments
|
287
|
|
|
257
|
|
|
151
|
|
|||
Atlantic-Gulf Modified EBITDA
|
$
|
1,600
|
|
|
$
|
1,523
|
|
|
$
|
1,065
|
|
|
|
|
|
|
|
||||||
NGL margin
|
$
|
38
|
|
|
$
|
27
|
|
|
$
|
57
|
|
•
|
A $79 million increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2015 and 2016, partially offset by lower volume-based transportation services revenues;
|
•
|
A $20 million increase in eastern Gulf Coast region fee revenues primarily related to the impact of new volumes at Gulfstar One related to the Gunflint expansion (which was placed in service in the third quarter of 2016), higher volumes at Devils Tower related to the Kodiak field (which began production in early 2016), and higher volumes from a temporary increase related to disrupted operations of a competitor. These increases were partially offset by lower volumes from the impact of 2016 producers’ operational issues and suspending operations in order to facilitate the tie-in of the Gunflint expansion at Gulfstar One;
|
•
|
A $15 million decrease in Transco’s storage revenue related to potential refunds associated with a ruling received in certain rate case litigation in 2016;
|
•
|
A $12 million decrease in western Gulf Coast region fee revenues primarily related to lower volumes associated with producer maintenance in 2016 and natural declines in certain production areas.
|
•
|
A $39 million decrease in system management gas sales from Transco. System management gas sales are offset in
Product costs
and, therefore, have no impact on
Modified EBITDA;
|
•
|
A $12 million decrease in crude oil and NGL marketing revenues. Crude oil marketing sales decreased $5 million primarily due to 13 percent lower crude oil per barrel sales prices, partially offset by 11 percent higher volumes. NGL marketing sales also decreased $7 million primarily due to 13 percent lower non-ethane volumes, partially offset by 35 percent higher ethane volumes and slightly higher ethane and non-ethane per-unit sales prices. These changes in marketing revenues are offset by similar changes in marketing purchases;
|
•
|
A $36 million increase in revenues from our equity NGLs primarily due to a temporary increase in keep-whole volumes due to disrupted operations of a competitor.
|
•
|
A $39 million decrease in system management gas costs (offset in
Product sales
)
;
|
•
|
A $17 million decrease in marketing purchases (substantially offset in
Product sales
);
|
•
|
A $25 million increase in natural gas purchases associated with the production of equity NGLs primarily due to higher volumes.
|
•
|
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.
|
•
|
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.
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Service revenues
|
$
|
1,034
|
|
|
$
|
1,055
|
|
|
$
|
1,050
|
|
Product sales
|
278
|
|
|
257
|
|
|
546
|
|
|||
Segment revenues
|
1,312
|
|
|
1,312
|
|
|
1,596
|
|
|||
|
|
|
|
|
|
||||||
Product costs
|
(159
|
)
|
|
(145
|
)
|
|
(270
|
)
|
|||
Other segment costs and expenses
|
(500
|
)
|
|
(513
|
)
|
|
(503
|
)
|
|||
Impairment of certain assets
|
(4
|
)
|
|
(97
|
)
|
|
—
|
|
|||
West Modified EBITDA
|
$
|
649
|
|
|
$
|
557
|
|
|
$
|
823
|
|
|
|
|
|
|
|
||||||
NGL margin
|
$
|
112
|
|
|
$
|
105
|
|
|
$
|
255
|
|
•
|
A $21 million increase in revenues from our equity NGLs associated with higher NGL volumes, partially offset by $5 million of lower NGL prices;
|
•
|
An $11 million increase in marketing revenues primarily due to higher non-ethane volumes (offset in
Product costs
).
|
•
|
An $11 million increase in NGL marketing purchases primarily due to higher non-ethane volumes (offset in
Product sales)
;
|
•
|
A $9 million increase in natural gas purchases associated with the production of equity NGLs due to higher volumes, partially offset by lower natural gas prices.
|
•
|
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;
|
•
|
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.
|
•
|
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.
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Service revenues
|
$
|
168
|
|
|
$
|
139
|
|
|
$
|
126
|
|
Product sales
|
2,102
|
|
|
1,921
|
|
|
2,986
|
|
|||
Segment revenues
|
2,270
|
|
|
2,060
|
|
|
3,112
|
|
|||
|
|
|
|
|
|
||||||
Product costs
|
(1,717
|
)
|
|
(1,656
|
)
|
|
(2,829
|
)
|
|||
Other segment costs and expenses
|
(296
|
)
|
|
(251
|
)
|
|
(241
|
)
|
|||
Net insurance recoveries – Geismar Incident
|
7
|
|
|
126
|
|
|
232
|
|
|||
Impairment of certain assets
|
(344
|
)
|
|
—
|
|
|
—
|
|
|||
Proportional Modified EBITDA of equity-method investments
|
57
|
|
|
42
|
|
|
50
|
|
|||
NGL & Petchem Services Modified EBITDA
|
$
|
(23
|
)
|
|
$
|
321
|
|
|
$
|
324
|
|
|
|
|
|
|
|
||||||
Olefins margin
|
$
|
337
|
|
|
$
|
226
|
|
|
$
|
110
|
|
NGL margin
|
12
|
|
|
21
|
|
|
68
|
|
•
|
A $140 million increase in marketing revenues primarily due to higher natural gas and NGL volumes, partially offset by primarily lower natural gas prices (substantially offset by higher
Product costs
);
|
•
|
A $94 million increase in olefin sales comprised of a $170 million increase from our Geismar plant that returned to service in late March 2015, partially offset by a $76 million decrease from our other olefin operations. The increase at Geismar includes $153 million associated with increased volumes as a result of the plant operating at higher production levels in 2016 than when production resumed in March 2015 following the Geismar Incident and $17 million primarily associated with higher ethylene per-unit sales prices. The decrease in other olefin sales includes a $14 million reduction due to the absence of our former Canadian operations in the fourth quarter of 2016, as well as lower volumes and lower per-unit sales prices within our other olefin operations;
|
•
|
A $49 million decrease in Canadian NGL production revenues comprised of a $41 million decrease associated with lower volumes and an $8 million decrease associated with lower prices across all products. The lower volumes include a $20 million reduction in the fourth quarter due to the sale of our Canadian operations in September 2016. The volume declines also reflect the shut-down and evacuation of the liquids extraction plant because of wild fires in the Fort McMurray area during the second quarter of 2016, and a longer period of planned maintenance in 2016.
|
•
|
A $132 million increase in marketing product costs primarily due to higher natural gas and NGL volumes, partially offset by primarily lower natural gas prices (more than offset by higher
Product sales
);
|
•
|
A $40 million decrease in NGL product costs due to a $29 million decrease in primarily propane and ethane volumes and an $11 million decrease reflecting a decline in the price of natural gas associated with the production of equity NGLs. The $29 million decline associated with lower volumes includes $13 million attributable to the fourth quarter of 2016, subsequent to the sale of our former Canadian operations;
|
•
|
A $17 million decrease in olefin feedstock purchases is primarily comprised of $78 million in lower purchases at our other olefins operations, partially offset by $61 million of higher purchases due primarily to increased volumes at our Geismar plant resulting from higher productions levels. The lower costs at our other olefin operations are comprised of $54 million in lower per-unit feedstock costs and $24 million in primarily lower propylene volumes;
|
•
|
Lower costs associated with various other products, primarily condensate.
|
•
|
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
|
•
|
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 an $84 million decrease from our other olefin operations due to lower sales prices, partially offset by higher volumes across all products, particularly propylene.
|
•
|
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 $29 million in lower other olefin operations feedstock purchases primarily due to lower per-unit feedstock costs, partially offset by higher volumes across most products, particularly propylene.
|
•
|
Expansion of Transco’s interstate natural gas pipeline system through projects such as Rock Springs to meet the demand of growth markets;
|
•
|
Completion of the Gulfstar One expansion project to provide production handling and gathering services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico;
|
•
|
Restructuring of contracts in the Barnett Shale and Mid-Continent region, which included cash payments to us of $820 million;
|
•
|
Sale of our Canadian operations. (See
Note 3 – Divestiture
of Notes to Consolidated Financial Statements.)
|
•
|
Cash and cash equivalents on hand;
|
•
|
Cash generated from operations;
|
•
|
Distributions from our equity-method investees based on our level of ownership;
|
•
|
Cash proceeds from the January 2017 and February 2017 purchase of common units by Williams (see
Note 15 – Partners’ Capital
of Notes to Consolidated Financial Statements);
|
•
|
Use of our credit facility and/or commercial paper program;
|
•
|
Proceeds from planned asset monetizations.
|
•
|
Working capital requirements;
|
•
|
Maintenance and expansion capital and investment expenditures;
|
•
|
Interest on our long-term debt;
|
•
|
Repayment of current debt maturities, and additional reductions in debt with funds received as part of the Financial Repositioning announced in January 2017;
|
•
|
Quarterly distributions to our unitholders.
|
Available Liquidity
|
December 31, 2016
|
||
|
(Millions)
|
||
Cash and cash equivalents
|
$
|
145
|
|
Capacity available under our $3.5 billion credit facility, less amounts outstanding under our $3 billion commercial paper program (1)
|
3,407
|
|
|
|
$
|
3,552
|
|
(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, 2016
, we had
$93 million
of
Commercial paper
outstanding. The highest amount outstanding under our commercial paper program and credit facility during 2016 was $2.326 billion. At
December 31, 2016
, we were in compliance with the financial covenants associated with this credit facility. See
Note 14 – 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 our $3.5 billion credit facility as of February 20, 2017, was $3.5 billion.
|
Rating Agency
|
|
Outlook
|
|
Senior Unsecured
Debt Rating
|
|
Corporate Credit Rating
|
S&P Global Ratings
|
|
Stable
|
|
BBB-
|
|
BBB-
|
Moody’s Investors Service
|
|
Stable
|
|
Baa3
|
|
N/A
|
Fitch Ratings
|
|
Stable
|
|
BBB-
|
|
N/A
|
|
Cash Flow
|
|
Years Ended December 31,
|
||||||||||
|
Category
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
|
(Millions)
|
||||||||||
Sources of cash and cash equivalents:
|
|
|
|
|
|
|
|
||||||
Operating activities - net
|
Operating
|
|
$
|
3,938
|
|
|
$
|
2,661
|
|
|
$
|
2,345
|
|
Proceeds from credit-facility borrowings
|
Financing
|
|
3,250
|
|
|
3,832
|
|
|
1,646
|
|
|||
Proceeds from debt offerings (see Note 14)
|
Financing
|
|
998
|
|
|
3,842
|
|
|
2,740
|
|
|||
Proceeds from sale of Canadian operations (see Note 3)
|
Investing
|
|
672
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from sales of common units (see Note 15)
|
Financing
|
|
614
|
|
|
59
|
|
|
55
|
|
|||
Distributions from unconsolidated affiliates in excess of cumulative earnings
|
Investing
|
|
472
|
|
|
404
|
|
|
141
|
|
|||
Contributions from noncontrolling interests
|
Financing
|
|
29
|
|
|
111
|
|
|
334
|
|
|||
Special distribution from Gulfstream (see Note 7)
|
Financing
|
|
—
|
|
|
396
|
|
|
—
|
|
|||
Proceeds from commercial paper - net
|
Financing
|
|
—
|
|
|
—
|
|
|
572
|
|
|||
|
|
|
|
|
|
|
|
||||||
Uses of cash and cash equivalents:
|
|
|
|
|
|
|
|
||||||
Payments on credit-facility borrowings
|
Financing
|
|
(4,560
|
)
|
|
(3,162
|
)
|
|
(1,156
|
)
|
|||
Distributions to limited partner unitholders and general partner (1)
|
Financing
|
|
(2,531
|
)
|
|
(2,686
|
)
|
|
(2,448
|
)
|
|||
Capital expenditures
|
Investing
|
|
(1,944
|
)
|
|
(2,795
|
)
|
|
(3,692
|
)
|
|||
Payments of commercial paper - net
|
Financing
|
|
(409
|
)
|
|
(306
|
)
|
|
—
|
|
|||
Payments on debt retirements (see Note 14)
|
Financing
|
|
(375
|
)
|
|
(1,533
|
)
|
|
—
|
|
|||
Purchases of and contributions to equity-method investments
|
Investing
|
|
(177
|
)
|
|
(594
|
)
|
|
(468
|
)
|
|||
Contribution to Gulfstream for repayment of debt (see Note 7)
|
Financing
|
|
(148
|
)
|
|
(248
|
)
|
|
—
|
|
|||
Dividends and distributions to noncontrolling interests
|
Financing
|
|
(92
|
)
|
|
(87
|
)
|
|
(243
|
)
|
|||
Purchases of businesses, net of cash acquired
|
Investing
|
|
—
|
|
|
(112
|
)
|
|
—
|
|
|||
|
|
|
|
|
|
|
|
||||||
Other sources / (uses) - net
|
Financing and Investing
|
|
312
|
|
|
143
|
|
|
235
|
|
|||
Increase (decrease) in cash and cash equivalents
|
|
|
$
|
49
|
|
|
$
|
(75
|
)
|
|
$
|
61
|
|
(1)
|
Includes $1.693 billion, $1.846 billion, and $1.867 billion to Williams in 2016, 2015, and 2014, respectively.
|
|
2017
|
|
2018 - 2019
|
|
2020 - 2021
|
|
Thereafter
|
|
Total
|
||||||||||
|
(Millions)
|
||||||||||||||||||
Long-term debt: (1)(2)
|
|
|
|
|
|
|
|
|
|
||||||||||
Principal
|
$
|
785
|
|
|
$
|
1,350
|
|
|
$
|
2,600
|
|
|
$
|
13,718
|
|
|
$
|
18,453
|
|
Interest
|
855
|
|
|
1,647
|
|
|
1,460
|
|
|
6,119
|
|
|
10,081
|
|
|||||
Commercial paper
|
93
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
93
|
|
|||||
Operating leases
|
52
|
|
|
83
|
|
|
58
|
|
|
71
|
|
|
264
|
|
|||||
Purchase obligations (3)
|
1,010
|
|
|
680
|
|
|
632
|
|
|
318
|
|
|
2,640
|
|
|||||
Other obligations (4)
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|||||
Total
|
$
|
2,796
|
|
|
$
|
3,761
|
|
|
$
|
4,750
|
|
|
$
|
20,226
|
|
|
$
|
31,533
|
|
(1)
|
Includes the borrowings outstanding under our credit facility, but does not include any related variable-rate interest payments.
|
(2)
|
Includes $750 million of 6.125 percent senior notes due 2022 that we intend to redeem on February 23, 2017 and related interest, presented in the table above according to the original contractual terms.
|
(3)
|
Includes approximately $244 million in open property, plant, and equipment purchase orders. Includes an estimated $418 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at
December 31, 2016
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 $619 million long-term ethane purchase obligation with index-based pricing terms that primarily supplies third parties at their plants and is valued in this table at a price calculated using
December 31, 2016
prices. Any excess purchased volumes may be sold at comparable market prices. Includes an estimated $586 million long-term mixed NGLs purchase obligation with index-based pricing terms that is reflected in this table at
December 31, 2016
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 9 – Provision (Benefit) for Income Taxes
of Notes to Consolidated Financial Statements for a discussion of income taxes.
|
(1)
|
Includes unamortized discount / premium and debt issuance costs.
|
(2)
|
Excludes capital leases.
|
(3)
|
The weighted-average interest rate for our $850 million term loan was 2.50 percent at
December 31, 2016
. 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.
|
(4)
|
The weighted-average interest rate was
1.06 percent
and 0.92 percent at
December 31, 2016
and
2015
, respectively.
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions, except per-unit amounts)
|
|||||||||||
Revenues:
|
|
|
|
|
|
|
||||||
Service revenues
|
|
$
|
5,173
|
|
|
$
|
5,135
|
|
|
$
|
3,888
|
|
Product sales
|
|
2,318
|
|
|
2,196
|
|
|
3,521
|
|
|||
Total revenues
|
|
7,491
|
|
|
7,331
|
|
|
7,409
|
|
|||
Costs and expenses:
|
|
|
|
|
|
|
||||||
Product costs
|
|
1,728
|
|
|
1,779
|
|
|
3,016
|
|
|||
Operating and maintenance expenses
|
|
1,548
|
|
|
1,625
|
|
|
1,277
|
|
|||
Depreciation and amortization expenses
|
|
1,720
|
|
|
1,702
|
|
|
1,151
|
|
|||
Selling, general, and administrative expenses
|
|
630
|
|
|
684
|
|
|
633
|
|
|||
Impairment of goodwill (Note 17)
|
|
—
|
|
|
1,098
|
|
|
—
|
|
|||
Impairment of certain assets (Note 17)
|
|
457
|
|
|
145
|
|
|
52
|
|
|||
Net insurance recoveries – Geismar Incident
|
|
(7
|
)
|
|
(126
|
)
|
|
(232
|
)
|
|||
Other (income) expense – net
|
|
118
|
|
|
41
|
|
|
(97
|
)
|
|||
Total costs and expenses
|
|
6,194
|
|
|
6,948
|
|
|
5,800
|
|
|||
Operating income (loss)
|
|
1,297
|
|
|
383
|
|
|
1,609
|
|
|||
Equity earnings (losses)
|
|
397
|
|
|
335
|
|
|
228
|
|
|||
Impairment of equity-method investments (Note 17)
|
|
(430
|
)
|
|
(1,359
|
)
|
|
—
|
|
|||
Other investing income (loss) – net
|
|
29
|
|
|
2
|
|
|
2
|
|
|||
Interest incurred
|
|
(949
|
)
|
|
(864
|
)
|
|
(683
|
)
|
|||
Interest capitalized
|
|
33
|
|
|
53
|
|
|
121
|
|
|||
Other income (expense) – net
|
|
62
|
|
|
93
|
|
|
36
|
|
|||
Income (loss) before income taxes
|
|
439
|
|
|
(1,357
|
)
|
|
1,313
|
|
|||
Provision (benefit) for income taxes
|
|
(80
|
)
|
|
1
|
|
|
29
|
|
|||
Net income (loss)
|
|
519
|
|
|
(1,358
|
)
|
|
1,284
|
|
|||
Less: Net income attributable to noncontrolling interests
|
|
88
|
|
|
91
|
|
|
96
|
|
|||
Net income (loss) attributable to controlling interests
|
|
$
|
431
|
|
|
$
|
(1,449
|
)
|
|
$
|
1,188
|
|
Allocation of net income (loss) for calculation of earnings per common unit:
|
|
|
|
|
|
|
||||||
Net income (loss) attributable to controlling interests
|
|
$
|
431
|
|
|
$
|
(1,449
|
)
|
|
$
|
1,188
|
|
Allocation of net income (loss) to general partner
|
|
517
|
|
|
384
|
|
|
756
|
|
|||
Allocation of net income (loss) to Class B units
|
|
12
|
|
|
(46
|
)
|
|
—
|
|
|||
Allocation of net income (loss) to Class D units
|
|
—
|
|
|
68
|
|
|
73
|
|
|||
Allocation of net income (loss) to common units
|
|
$
|
(98
|
)
|
|
$
|
(1,855
|
)
|
|
$
|
359
|
|
Basic and diluted earnings (loss) per common unit:
|
|
|
|
|
|
|
||||||
Net income (loss) per common unit
|
|
$
|
(.17
|
)
|
|
$
|
(3.27
|
)
|
|
$
|
.99
|
|
Weighted average number of common units outstanding (thousands)
|
|
592,519
|
|
|
567,275
|
|
|
361,968
|
|
|||
Cash distributions per common unit
|
|
$
|
3.4000
|
|
|
$
|
3.4000
|
|
|
$
|
3.5995
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
||||||
Cash flow hedging activities:
|
|
|
|
|
|
|
||||||
Net unrealized gain (loss) from derivative instruments
|
|
$
|
5
|
|
|
$
|
6
|
|
|
$
|
(1
|
)
|
Reclassifications into earnings of net derivative instruments (gain) loss
|
|
(3
|
)
|
|
(7
|
)
|
|
—
|
|
|||
Foreign currency translation activities:
|
|
|
|
|
|
|
||||||
Foreign currency translation adjustments
|
|
61
|
|
|
(173
|
)
|
|
(89
|
)
|
|||
Reclassification into earnings upon sale of foreign entity
|
|
108
|
|
|
—
|
|
|
—
|
|
|||
Other comprehensive income (loss)
|
|
171
|
|
|
(174
|
)
|
|
(90
|
)
|
|||
Comprehensive income (loss)
|
|
690
|
|
|
(1,532
|
)
|
|
1,194
|
|
|||
Less: Comprehensive income attributable to noncontrolling interests
|
|
88
|
|
|
91
|
|
|
96
|
|
|||
Comprehensive income (loss) attributable to controlling interests
|
|
$
|
602
|
|
|
$
|
(1,623
|
)
|
|
$
|
1,098
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
145
|
|
|
$
|
96
|
|
Trade accounts and other receivables (net of allowance of $6 at December 31, 2016 and $3 at December 31, 2015)
|
926
|
|
|
1,026
|
|
||
Inventories
|
138
|
|
|
127
|
|
||
Other current assets and deferred charges
|
205
|
|
|
190
|
|
||
Total current assets
|
1,414
|
|
|
1,439
|
|
||
Investments
|
6,701
|
|
|
7,336
|
|
||
Property, plant, and equipment – net
|
28,021
|
|
|
28,600
|
|
||
Intangible assets – net of accumulated amortization
|
9,662
|
|
|
10,016
|
|
||
Regulatory assets, deferred charges, and other
|
467
|
|
|
479
|
|
||
Total assets
|
$
|
46,265
|
|
|
$
|
47,870
|
|
LIABILITIES AND EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable:
|
|
|
|
||||
Trade
|
$
|
589
|
|
|
$
|
648
|
|
Affiliate
|
109
|
|
|
141
|
|
||
Accrued interest
|
258
|
|
|
231
|
|
||
Asset retirement obligations
|
61
|
|
|
57
|
|
||
Other accrued liabilities
|
804
|
|
|
469
|
|
||
Commercial paper
|
93
|
|
|
499
|
|
||
Long-term debt due within one year
|
785
|
|
|
176
|
|
||
Total current liabilities
|
2,699
|
|
|
2,221
|
|
||
Long-term debt
|
17,685
|
|
|
19,001
|
|
||
Asset retirement obligations
|
798
|
|
|
857
|
|
||
Deferred income tax liabilities
|
20
|
|
|
119
|
|
||
Regulatory liabilities, deferred income, and other
|
1,860
|
|
|
1,066
|
|
||
Contingent liabilities and commitments (Note 18)
|
|
|
|
|
|||
Equity:
|
|
|
|
||||
Partners’ equity:
|
|
|
|
||||
Common units (607,064,550 and 588,546,022 units outstanding at December 31, 2016 and 2015, respectively)
|
18,300
|
|
|
19,730
|
|
||
Class B units (16,690,016 and 14,784,015 units outstanding as of December 31, 2016 and 2015, respectively)
|
769
|
|
|
771
|
|
||
General partner
|
2,385
|
|
|
2,552
|
|
||
Accumulated other comprehensive income (loss)
|
(1
|
)
|
|
(172
|
)
|
||
Total partners’ equity
|
21,453
|
|
|
22,881
|
|
||
Noncontrolling interests in consolidated subsidiaries
|
1,750
|
|
|
1,725
|
|
||
Total equity
|
23,203
|
|
|
24,606
|
|
||
Total liabilities and equity
|
$
|
46,265
|
|
|
$
|
47,870
|
|
|
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, 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 15)
|
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 5)
|
(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 15)
|
59
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
59
|
|
|
—
|
|
|
59
|
|
||||||||
Amortization of beneficial conversion feature of Class D units (Note 5)
|
(68
|
)
|
|
—
|
|
|
68
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Conversion of Class D units to common units (Note 5)
|
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
|
|
Net income (loss)
|
(57
|
)
|
|
(2
|
)
|
|
—
|
|
|
490
|
|
|
—
|
|
|
431
|
|
|
88
|
|
|
519
|
|
||||||||
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
171
|
|
|
171
|
|
|
—
|
|
|
171
|
|
||||||||
Noncash consideration from The Williams Companies, Inc. (Note 3)
|
—
|
|
|
—
|
|
|
—
|
|
|
(150
|
)
|
|
—
|
|
|
(150
|
)
|
|
—
|
|
|
(150
|
)
|
||||||||
Sales of common units (Note 15)
|
624
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
624
|
|
|
—
|
|
|
624
|
|
||||||||
Distributions to limited partners and general partner
|
(2,007
|
)
|
|
—
|
|
|
—
|
|
|
(533
|
)
|
|
—
|
|
|
(2,540
|
)
|
|
—
|
|
|
(2,540
|
)
|
||||||||
Contributions from general partner
|
—
|
|
|
—
|
|
|
—
|
|
|
26
|
|
|
—
|
|
|
26
|
|
|
—
|
|
|
26
|
|
||||||||
Contributions from noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
29
|
|
|
29
|
|
||||||||
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(92
|
)
|
|
(92
|
)
|
||||||||
Other
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
||||||||
Net increase (decrease) in equity
|
(1,430
|
)
|
|
(2
|
)
|
|
—
|
|
|
(167
|
)
|
|
171
|
|
|
(1,428
|
)
|
|
25
|
|
|
(1,403
|
)
|
||||||||
Balance – December 31, 2016
|
$
|
18,300
|
|
|
$
|
769
|
|
|
$
|
—
|
|
|
$
|
2,385
|
|
|
$
|
(1
|
)
|
|
$
|
21,453
|
|
|
$
|
1,750
|
|
|
$
|
23,203
|
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
OPERATING ACTIVITIES:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
519
|
|
|
$
|
(1,358
|
)
|
|
$
|
1,284
|
|
Adjustments to reconcile to net cash provided (used) by operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization
|
1,720
|
|
|
1,702
|
|
|
1,151
|
|
|||
Provision (benefit) for deferred income taxes
|
(83
|
)
|
|
4
|
|
|
25
|
|
|||
Impairment of goodwill
|
—
|
|
|
1,098
|
|
|
—
|
|
|||
Impairment of equity-method investments
|
430
|
|
|
1,359
|
|
|
—
|
|
|||
Impairment of and net (gain) loss on sale of assets and businesses
|
481
|
|
|
150
|
|
|
68
|
|
|||
Amortization of stock-based awards
|
20
|
|
|
27
|
|
|
9
|
|
|||
Cash provided (used) by changes in current assets and liabilities:
|
|
|
|
|
|
||||||
Accounts and notes receivable
|
80
|
|
|
(67
|
)
|
|
(169
|
)
|
|||
Inventories
|
(20
|
)
|
|
105
|
|
|
(36
|
)
|
|||
Other current assets and deferred charges
|
(2
|
)
|
|
2
|
|
|
(43
|
)
|
|||
Accounts payable
|
5
|
|
|
(128
|
)
|
|
(42
|
)
|
|||
Accrued liabilities
|
503
|
|
|
(15
|
)
|
|
(233
|
)
|
|||
Affiliate accounts receivable and payable – net
|
(37
|
)
|
|
—
|
|
|
9
|
|
|||
Other, including changes in noncurrent assets and liabilities
|
322
|
|
|
(218
|
)
|
|
322
|
|
|||
Net cash provided (used) by operating activities
|
3,938
|
|
|
2,661
|
|
|
2,345
|
|
|||
FINANCING ACTIVITIES:
|
|
|
|
|
|
||||||
Proceeds from (payments of) commercial paper – net
|
(409
|
)
|
|
(306
|
)
|
|
572
|
|
|||
Proceeds from long-term debt
|
4,248
|
|
|
7,675
|
|
|
4,386
|
|
|||
Payments of long-term debt
|
(4,936
|
)
|
|
(4,699
|
)
|
|
(1,157
|
)
|
|||
Proceeds from sales of common units
|
614
|
|
|
59
|
|
|
55
|
|
|||
Contributions from general partner
|
26
|
|
|
14
|
|
|
13
|
|
|||
Distributions to limited partners and general partner
|
(2,531
|
)
|
|
(2,686
|
)
|
|
(2,448
|
)
|
|||
Distributions to noncontrolling interests
|
(92
|
)
|
|
(87
|
)
|
|
(243
|
)
|
|||
Contributions from noncontrolling interests
|
29
|
|
|
111
|
|
|
334
|
|
|||
Contributions from The Williams Companies, Inc. – net
|
—
|
|
|
20
|
|
|
73
|
|
|||
Payments for debt issuance costs
|
(9
|
)
|
|
(33
|
)
|
|
(24
|
)
|
|||
Special distribution from Gulfstream
|
—
|
|
|
396
|
|
|
—
|
|
|||
Contribution to Gulfstream for repayment of debt
|
(148
|
)
|
|
(248
|
)
|
|
—
|
|
|||
Other – net
|
—
|
|
|
(1
|
)
|
|
24
|
|
|||
Net cash provided (used) by financing activities
|
(3,208
|
)
|
|
215
|
|
|
1,585
|
|
|||
INVESTING ACTIVITIES:
|
|
|
|
|
|
||||||
Property, plant, and equipment:
|
|
|
|
|
|
||||||
Capital expenditures (1)
|
(1,944
|
)
|
|
(2,795
|
)
|
|
(3,692
|
)
|
|||
Net proceeds from dispositions
|
6
|
|
|
3
|
|
|
34
|
|
|||
Proceeds from sale of businesses, net of cash divested
|
672
|
|
|
—
|
|
|
—
|
|
|||
Purchases of businesses, net of cash acquired
|
—
|
|
|
(112
|
)
|
|
—
|
|
|||
Purchases of and contributions to equity-method investments
|
(177
|
)
|
|
(594
|
)
|
|
(468
|
)
|
|||
Distributions from unconsolidated affiliates in excess of cumulative earnings
|
472
|
|
|
404
|
|
|
141
|
|
|||
Other – net
|
290
|
|
|
143
|
|
|
116
|
|
|||
Net cash provided (used) by investing activities
|
(681
|
)
|
|
(2,951
|
)
|
|
(3,869
|
)
|
|||
Increase (decrease) in cash and cash equivalents
|
49
|
|
|
(75
|
)
|
|
61
|
|
|||
Cash and cash equivalents at beginning of year
|
96
|
|
|
171
|
|
|
110
|
|
|||
Cash and cash equivalents at end of year
|
$
|
145
|
|
|
$
|
96
|
|
|
$
|
171
|
|
_________
|
|
|
|
|
|
||||||
(1) Increases to property, plant, and equipment
|
$
|
(1,871
|
)
|
|
$
|
(2,649
|
)
|
|
$
|
(3,571
|
)
|
Changes in related accounts payable and accrued liabilities
|
(73
|
)
|
|
(146
|
)
|
|
(121
|
)
|
|||
Capital expenditures
|
$
|
(1,944
|
)
|
|
$
|
(2,795
|
)
|
|
$
|
(3,692
|
)
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
•
|
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;
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
•
|
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.
|
•
|
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.
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
Current assets reported within
Other current assets and deferred charges
|
$
|
91
|
|
|
$
|
84
|
|
Noncurrent assets reported within
Regulatory assets, deferred charges, and other
|
299
|
|
|
305
|
|
||
Total regulated assets
|
$
|
390
|
|
|
$
|
389
|
|
|
|
|
|
||||
Current liabilities reported within
Other accrued liabilities
|
$
|
11
|
|
|
$
|
4
|
|
Noncurrent liabilities reported within
Regulatory liabilities, deferred income, and other
|
480
|
|
|
409
|
|
||
Total regulated liabilities
|
$
|
491
|
|
|
$
|
413
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
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
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
|
December 31,
|
||
|
|
2014
|
||
|
|
(Millions)
|
||
Total revenues
|
|
$
|
7,953
|
|
Net income (loss) attributable to controlling interests
|
|
$
|
1,376
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
Years Ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
Income (loss) before income taxes of disposal group
|
$
|
(9
|
)
|
|
$
|
6
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
December 31,
|
|
|
||||||
|
2016
|
|
2015
|
|
Classification
|
||||
|
(Millions)
|
|
|
||||||
Assets (liabilities):
|
|
|
|
|
|
||||
Cash and cash equivalents
|
$
|
82
|
|
|
$
|
70
|
|
|
Cash and cash equivalents
|
Accounts receivable
|
91
|
|
|
71
|
|
|
Trade accounts and other receivables
|
||
Prepaid assets
|
3
|
|
|
2
|
|
|
Other current assets and deferred charges
|
||
Property, plant, and equipment
–
net
|
3,024
|
|
|
3,000
|
|
|
Property, plant, and equipment – net
|
||
Intangible assets
–
net
|
1,431
|
|
|
1,483
|
|
|
Intangible assets – net of accumulated amortization
|
||
Accounts payable
|
(44
|
)
|
|
(59
|
)
|
|
Accounts payable – trade
|
||
Accrued liabilities
|
(3
|
)
|
|
(14
|
)
|
|
Other accrued liabilities
|
||
Current deferred revenue
|
(63
|
)
|
|
(62
|
)
|
|
Other accrued liabilities
|
||
Noncurrent asset retirement obligations
|
(99
|
)
|
|
(93
|
)
|
|
Asset retirement obligations
|
||
Noncurrent deferred revenue associated with customer advance payments
|
(324
|
)
|
|
(331
|
)
|
|
Regulatory liabilities, deferred income, and other
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Allocation of net income to general partner:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
519
|
|
|
$
|
(1,358
|
)
|
|
$
|
1,284
|
|
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
|
)
|
|||
Net income applicable to noncontrolling interests
|
(88
|
)
|
|
(91
|
)
|
|
(96
|
)
|
|||
Costs charged directly to the general partner
|
1
|
|
|
21
|
|
|
1
|
|
|||
Income (loss) subject to 2% allocation of general partner interest
|
432
|
|
|
(1,430
|
)
|
|
1,079
|
|
|||
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
|
9
|
|
|
(29
|
)
|
|
22
|
|
|||
Priority allocations, including incentive distributions, paid to general partner
|
482
|
|
|
638
|
|
|
641
|
|
|||
Pre-merger net income allocated to general partner interest
|
—
|
|
|
2
|
|
|
95
|
|
|||
Pre-partnership net income allocated to general partner interest
|
—
|
|
|
—
|
|
|
15
|
|
|||
Costs charged directly to the general partner
|
(1
|
)
|
|
(21
|
)
|
|
(1
|
)
|
|||
Net income allocated to general partner’s equity
|
$
|
490
|
|
|
$
|
590
|
|
|
$
|
772
|
|
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
519
|
|
|
$
|
(1,358
|
)
|
|
$
|
1,284
|
|
Net income allocated to general partner’s equity
|
490
|
|
|
590
|
|
|
772
|
|
|||
Net income (loss) allocated to Class B limited partners’ equity
|
(2
|
)
|
|
(52
|
)
|
|
—
|
|
|||
Net income allocated to Class D limited partners’ equity (1)
|
—
|
|
|
69
|
|
|
62
|
|
|||
Net income allocated to noncontrolling interests
|
88
|
|
|
91
|
|
|
96
|
|
|||
Net income (loss) allocated to common limited partners’ equity
|
$
|
(57
|
)
|
|
$
|
(2,056
|
)
|
|
$
|
354
|
|
|
|
|
|
|
|
||||||
Adjustments to reconcile
Net income (loss) allocated to common limited partners' equity
to
Allocation of net income (loss) to common units:
|
|
|
|
|
|
||||||
Incentive distributions paid
|
474
|
|
|
633
|
|
|
640
|
|
|||
Incentive distributions declared
|
(473
|
)
|
|
(423
|
)
|
|
(626
|
)
|
|||
Impact of unit issuance timing and other (2)
|
(42
|
)
|
|
(9
|
)
|
|
(9
|
)
|
|||
Allocation of net income (loss) to common units
|
$
|
(98
|
)
|
|
$
|
(1,855
|
)
|
|
$
|
359
|
|
|
|
|
|
|
|
(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)
|
The 2016 amount includes the effect of units issued and the conversion of the general partner interest in us to a non-economic interest in conjunction with our Financial Repositioning (see
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
.)
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
•
|
Purchases of NGLs for resale from Discovery;
|
•
|
Payments to OPPL for transportation of NGLs from certain natural gas processing plants;
|
•
|
Purchases of NGLs for resale from Williams’ former Horizon liquids extraction plant in Canada.
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(Millions)
|
||||||||||
Service revenues
|
|
$
|
31
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Product costs
|
|
181
|
|
|
169
|
|
|
186
|
|
|||
Operating and maintenance expenses - employee costs
|
|
470
|
|
|
498
|
|
|
413
|
|
|||
Selling, general, and administrative expenses:
|
|
|
|
|
|
|
||||||
Employee direct costs
|
|
344
|
|
|
368
|
|
|
331
|
|
|||
Employee allocated costs
|
|
160
|
|
|
195
|
|
|
171
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
|
Years Ended December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
|
|
(Millions)
|
||||||
Northeast G&P
|
|
|
|
|
||||
Appalachia Midstream Investments
|
|
$
|
294
|
|
|
$
|
562
|
|
Laurel Mountain
|
|
50
|
|
|
45
|
|
||
UEOM
|
|
—
|
|
|
241
|
|
||
Central
|
|
|
|
|
||||
DBJV
|
|
59
|
|
|
503
|
|
||
Ranch Westex
|
|
24
|
|
|
—
|
|
||
Other
|
|
3
|
|
|
8
|
|
||
|
|
$
|
430
|
|
|
$
|
1,359
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
Ownership Interest at December 31, 2016
|
|
December 31,
|
||||||
|
|
2016
|
|
2015
|
|||||
|
|
|
(Millions)
|
||||||
Appalachia Midstream Investments
|
(1)
|
|
$
|
2,062
|
|
|
$
|
2,464
|
|
UEOM
|
62%
|
|
1,448
|
|
|
1,525
|
|
||
DBJV
|
50%
|
|
988
|
|
|
977
|
|
||
Discovery
|
60%
|
|
572
|
|
|
602
|
|
||
OPPL
|
50%
|
|
430
|
|
|
445
|
|
||
Caiman II
|
58%
|
|
426
|
|
|
418
|
|
||
Laurel Mountain
|
69%
|
|
324
|
|
|
391
|
|
||
Gulfstream
|
50%
|
|
261
|
|
|
293
|
|
||
Other
|
Various
|
|
190
|
|
|
221
|
|
||
|
|
|
$
|
6,701
|
|
|
$
|
7,336
|
|
(1)
|
Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average
41 percent
interest.
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
DBJV
|
$
|
105
|
|
|
$
|
57
|
|
|
$
|
20
|
|
Appalachia Midstream Investments
|
28
|
|
|
93
|
|
|
84
|
|
|||
Caiman II
|
22
|
|
|
—
|
|
|
175
|
|
|||
UEOM
|
—
|
|
|
357
|
|
|
57
|
|
|||
Discovery
|
—
|
|
|
35
|
|
|
106
|
|
|||
Other
|
22
|
|
|
52
|
|
|
26
|
|
|||
|
$
|
177
|
|
|
$
|
594
|
|
|
$
|
468
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Appalachia Midstream Investments
|
$
|
211
|
|
|
$
|
219
|
|
|
$
|
130
|
|
Discovery
|
141
|
|
|
116
|
|
|
36
|
|
|||
Gulfstream
|
100
|
|
|
88
|
|
|
81
|
|
|||
UEOM
|
92
|
|
|
42
|
|
|
—
|
|
|||
OPPL
|
69
|
|
|
45
|
|
|
27
|
|
|||
Caiman II
|
40
|
|
|
33
|
|
|
13
|
|
|||
DBJV
|
39
|
|
|
33
|
|
|
—
|
|
|||
Laurel Mountain
|
28
|
|
|
31
|
|
|
39
|
|
|||
Other
|
22
|
|
|
26
|
|
|
39
|
|
|||
|
$
|
742
|
|
|
$
|
633
|
|
|
$
|
365
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
Assets (liabilities):
|
|
|
|
||||
Current assets
|
$
|
508
|
|
|
$
|
773
|
|
Noncurrent assets
|
9,695
|
|
|
9,549
|
|
||
Current liabilities
|
(412
|
)
|
|
(633
|
)
|
||
Noncurrent liabilities
|
(1,484
|
)
|
|
(1,450
|
)
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(Millions)
|
||||||||||
Central
|
|
|
|
|
|
|
||||||
Loss related to sale of certain assets
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
10
|
|
Northeast G&P
|
|
|
|
|
|
|
||||||
Contingency gain settlement (1)
|
|
—
|
|
|
—
|
|
|
(154
|
)
|
|||
Net gain related to partial acreage dedication release
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
|||
Atlantic-Gulf
|
|
|
|
|
|
|
||||||
Amortization of regulatory assets associated with asset retirement obligations
|
|
33
|
|
|
33
|
|
|
33
|
|
|||
Accrual of regulatory liability related to overcollection of certain employee expenses
|
|
25
|
|
|
20
|
|
|
14
|
|
|||
Project development costs related to Constitution (Note 4)
|
|
28
|
|
|
—
|
|
|
—
|
|
|||
Gain on asset retirement
|
|
(11
|
)
|
|
—
|
|
|
—
|
|
|||
NGL & Petchem Services
|
|
|
|
|
|
|
||||||
Loss on sale of Canadian operations (Note 3)
|
|
34
|
|
|
—
|
|
|
—
|
|
|||
Net foreign currency exchange (gains) losses (2)
|
|
10
|
|
|
(10
|
)
|
|
(3
|
)
|
(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.
|
(2)
|
Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S. dollar-denominated current assets and liabilities within our former Canadian operations (see
Note 3 – Divestiture
).
|
•
|
Selling, general, and administrative expenses
includes
$26 million
in 2015 and
$27 million
in 2014 (including
$16 million
of acquisition costs) primarily related to professional advisory fees within the Central segment.
|
•
|
Selling, general, and administrative expenses
includes
$9 million
in 2015 and
$15 million
in 2014 of related employee transition costs within the Central segment.
|
•
|
Operating and maintenance expenses
includes
$12 million
in 2015 and
$15 million
in 2014 primarily related to employee transition costs within the Central segment.
|
•
|
Interest incurred
includes transaction-related financing costs of
$2 million
in 2015 from the merger and
$9 million
in 2014 from the acquisition.
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
•
|
Service revenues
includes
$173 million
associated with the amortization of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-Continent regions.
Service revenues
also includes
$58 million
,
$239 million
, and
$167 million
recognized in the fourth quarter of 2016, 2015, and 2014, respectively, from minimum volume commitment fees
in the Barnett Shale and Mid-Continent regions within the Central segment.
|
•
|
Selling, general, and administrative expenses
and
Operating and maintenance expenses
include
$37 million
in 2016 of severance and other related costs. Amounts by segment
are as follows:
|
|
Year Ended December 31, 2016
|
||
|
(Millions)
|
||
Central
|
$
|
8
|
|
Northeast G&P
|
3
|
|
|
Atlantic-Gulf
|
8
|
|
|
West
|
5
|
|
|
NGL & Petchem Services
|
4
|
|
|
Other
|
9
|
|
•
|
Other income (expense) – net
below
Operating income (loss)
includes
$65 million
,
$76 million
,and
$33 million
in 2016, 2015, and 2014, respectively, for equity AFUDC within the Atlantic-Gulf segment.
|
•
|
Other income (expense) – net
below
Operating income (loss)
includes a
$14 million
gain in 2015 resulting from the early retirement of certain debt.
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Current:
|
|
|
|
|
|
||||||
State
|
$
|
2
|
|
|
$
|
(3
|
)
|
|
$
|
3
|
|
Foreign
|
1
|
|
|
—
|
|
|
1
|
|
|||
|
3
|
|
|
(3
|
)
|
|
4
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
State
|
(1
|
)
|
|
(3
|
)
|
|
8
|
|
|||
Foreign
|
(82
|
)
|
|
7
|
|
|
17
|
|
|||
|
(83
|
)
|
|
4
|
|
|
25
|
|
|||
Provision (benefit) for income taxes
|
$
|
(80
|
)
|
|
$
|
1
|
|
|
$
|
29
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(Millions)
|
||||||||||
Provision (benefit) at statutory rate
|
$
|
154
|
|
|
$
|
(475
|
)
|
|
$
|
459
|
|
Increases (decreases) in taxes resulting from:
|
|
|
|
|
|
||||||
Income not subject to U.S. federal tax
|
(154
|
)
|
|
475
|
|
|
(459
|
)
|
|||
State income taxes
|
1
|
|
|
(6
|
)
|
|
11
|
|
|||
Foreign operations — net
|
(81
|
)
|
|
7
|
|
|
18
|
|
|||
Provision (benefit) for income taxes
|
$
|
(80
|
)
|
|
$
|
1
|
|
|
$
|
29
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
Estimated
|
|
Depreciation
|
|
|
|
|
||||
|
Useful Life (1)
|
|
Rates (1)
|
|
December 31,
|
||||||
|
(Years)
|
|
(%)
|
|
2016
|
|
2015
|
||||
|
|
|
|
|
(Millions)
|
||||||
Nonregulated:
|
|
|
|
|
|
|
|
||||
Natural gas gathering and processing facilities
|
5 - 40
|
|
|
|
$
|
20,267
|
|
|
$
|
20,636
|
|
Construction in progress
|
Not applicable
|
|
|
|
355
|
|
|
740
|
|
||
Other
|
3 - 45
|
|
|
|
1,740
|
|
|
1,743
|
|
||
Regulated:
|
|
|
|
|
|
|
|
||||
Natural gas transmission facilities
|
|
|
1.2 - 6.97
|
|
12,692
|
|
|
12,189
|
|
||
Construction in progress
|
Not applicable
|
|
Not applicable
|
|
1,603
|
|
|
941
|
|
||
Other
|
5 - 45
|
|
1.35 - 33.33
|
|
1,590
|
|
|
1,584
|
|
||
Total property, plant, and equipment, at cost
|
|
|
|
|
$
|
38,247
|
|
|
$
|
37,833
|
|
Accumulated depreciation and amortization
|
|
|
|
|
(10,226
|
)
|
|
(9,233
|
)
|
||
Property, plant, and equipment – net
|
|
|
|
|
$
|
28,021
|
|
|
$
|
28,600
|
|
(1)
|
Estimated useful life and depreciation rates are presented as of
December 31, 2016
. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
(1)
|
Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2016 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and decreases in the inflation rate and discount rates used in the annual review process. 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.
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
Central
|
|
Northeast G&P
|
|
West
|
|
Total
|
||||||||
|
(Millions)
|
||||||||||||||
December 31, 2014
|
$
|
240
|
|
|
$
|
835
|
|
|
$
|
45
|
|
|
$
|
1,120
|
|
Purchase accounting adjustment
|
10
|
|
|
13
|
|
|
2
|
|
|
25
|
|
||||
Impairment
|
(250
|
)
|
|
(848
|
)
|
|
—
|
|
|
(1,098
|
)
|
||||
December 31, 2015
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
47
|
|
|
$
|
47
|
|
December 31, 2016
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
47
|
|
|
$
|
47
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
Deferred income
|
$
|
338
|
|
|
$
|
94
|
|
Refundable deposits
|
160
|
|
|
—
|
|
||
Special distribution repayable to Gulfstream (See Note 7 - Investing Activities)
|
—
|
|
|
149
|
|
||
Other, including other loss contingencies
|
306
|
|
|
226
|
|
||
|
$
|
804
|
|
|
$
|
469
|
|
|
|
December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
|
|
(Millions)
|
||||||
Unsecured:
|
|
|
|
|
||||
Transco:
|
|
|
|
|
||||
6.4% Notes due 2016 (1)
|
|
$
|
—
|
|
|
$
|
200
|
|
6.05% Notes due 2018
|
|
250
|
|
|
250
|
|
||
7.08% Debentures due 2026
|
|
8
|
|
|
8
|
|
||
7.25% Debentures due 2026
|
|
200
|
|
|
200
|
|
||
7.85% Notes due 2026
|
|
1,000
|
|
|
—
|
|
||
5.4% Notes due 2041
|
|
375
|
|
|
375
|
|
||
4.45% Notes due 2042
|
|
400
|
|
|
400
|
|
||
Northwest Pipeline:
|
|
|
|
|
||||
7% Notes due 2016
|
|
—
|
|
|
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.:
|
|
|
|
|
||||
7.25% Notes due 2017
|
|
600
|
|
|
600
|
|
||
5.25% Notes due 2020
|
|
1,500
|
|
|
1,500
|
|
||
4.125% Notes due 2020
|
|
600
|
|
|
600
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
|
December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
|
|
(Millions)
|
||||||
4% Notes due 2021
|
|
500
|
|
|
500
|
|
||
3.6% Notes due 2022
|
|
1,250
|
|
|
1,250
|
|
||
3.35% Notes due 2022
|
|
750
|
|
|
750
|
|
||
6.125% Notes due 2022
|
|
750
|
|
|
750
|
|
||
4.5% Notes due 2023
|
|
600
|
|
|
600
|
|
||
4.875% Notes due 2023
|
|
1,400
|
|
|
1,400
|
|
||
4.3% Notes due 2024
|
|
1,000
|
|
|
1,000
|
|
||
4.875% Notes due 2024
|
|
750
|
|
|
750
|
|
||
3.9% Notes due 2025
|
|
750
|
|
|
750
|
|
||
4% Notes due 2025
|
|
750
|
|
|
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
|
|
|
1,000
|
|
||
Term Loan, variable interest rate, due 2018
|
|
850
|
|
|
850
|
|
||
Credit facility loans
|
|
—
|
|
|
1,310
|
|
||
Capital lease obligations
|
|
—
|
|
|
1
|
|
||
Debt issuance costs
|
|
(90
|
)
|
|
(91
|
)
|
||
Net unamortized debt premium (discount)
|
|
107
|
|
|
129
|
|
||
Long-term debt, including current portion
|
|
18,470
|
|
|
19,177
|
|
||
Long-term debt due within one year
|
|
(785
|
)
|
|
(176
|
)
|
||
Long-term debt
|
|
$
|
17,685
|
|
|
$
|
19,001
|
|
(1)
|
Presented as long-term debt at December 31, 2015, due to Transco’s intent and ability to refinance.
|
|
December 31,
2016 |
||
|
(Millions)
|
||
2017
|
$
|
785
|
|
2018
|
1,350
|
|
|
2019
|
—
|
|
|
2020
|
2,100
|
|
|
2021
|
500
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
December 31, 2016
|
||||||
|
Available
|
|
Outstanding
|
||||
|
(Millions)
|
||||||
Long-term credit facility (1)
|
$
|
3,500
|
|
|
$
|
—
|
|
Letters of credit under certain bilateral bank agreements
|
|
|
1
|
|
(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.
|
•
|
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
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
•
|
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.
|
•
|
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.
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
December 31,
2016 |
||
|
(Millions)
|
||
2017
|
$
|
48
|
|
2018
|
44
|
|
|
2019
|
39
|
|
|
2020
|
34
|
|
|
2021
|
24
|
|
|
Thereafter
|
71
|
|
|
Total
|
$
|
260
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
•
|
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.
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
|
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
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
Restricted Common Units Outstanding
|
Units
|
|
Weighted-
Average
Fair Value
|
|||
|
(Millions)
|
|
|
|||
Nonvested at December 31, 2015
|
1.2
|
|
|
$
|
55.93
|
|
Forfeited
|
(0.1
|
)
|
|
$
|
52.85
|
|
Vested
|
(0.5
|
)
|
|
$
|
59.09
|
|
Nonvested at December 31, 2016
|
0.6
|
|
|
$
|
52.97
|
|
|
|
|
|
|
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, 2016:
|
|
|
|
|
|
|
|
|
|
||||||||||
Measured on a recurring basis:
|
|
|
|
|
|
|
|
|
|
||||||||||
ARO Trust investments
|
$
|
96
|
|
|
$
|
96
|
|
|
$
|
96
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Energy derivatives assets designated as hedging instruments
|
2
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|||||
Energy derivatives assets not designated as hedging instruments
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Energy derivatives liabilities not designated as hedging instruments
|
(6
|
)
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|||||
Additional disclosures:
|
|
|
|
|
|
|
|
|
|
||||||||||
Other receivables
|
15
|
|
|
15
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|||||
Long-term debt, including current portion
|
(18,470
|
)
|
|
(18,907
|
)
|
|
—
|
|
|
(18,907
|
)
|
|
—
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
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:
|
|
|
|
|
|
|
|
|
|
||||||||||
Other receivables
|
12
|
|
|
12
|
|
|
10
|
|
|
2
|
|
|
—
|
|
|||||
Long-term debt, including current portion (1)
|
(19,176
|
)
|
|
(15,988
|
)
|
|
—
|
|
|
(15,988
|
)
|
|
—
|
|
(1)
|
Excludes capital leases.
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
|
|
|
|
|
|
|
|
Impairments
|
||||||||||||
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
||||||||||||
|
Classification
|
|
Segment
|
|
Date of Measurement
|
|
Fair Value
|
|
2016
|
|
2015
|
|
2014
|
||||||||
|
|
|
|
|
|
|
(Millions)
|
||||||||||||||
Surplus equipment (1)
|
Property, plant, and equipment – net
|
|
Northeast G&P
|
|
June 30, 2014
|
|
$
|
46
|
|
|
|
|
|
|
$
|
17
|
|
||||
Surplus equipment (1)
|
Property, plant, and equipment – net
|
|
Northeast G&P
|
|
December 31, 2014
|
|
32
|
|
|
|
|
|
|
13
|
|
||||||
Surplus equipment (1)
|
Property, plant, and equipment – net
|
|
Northeast G&P
|
|
June 30, 2015
|
|
17
|
|
|
|
|
$
|
20
|
|
|
|
|||||
Surplus equipment (1)
|
Assets held for sale
|
|
Central
|
|
December 31, 2014
|
|
1
|
|
|
|
|
|
|
12
|
|
||||||
Previously capitalized project development costs (2)
|
Property, plant, and equipment – net
|
|
West
|
|
December 31, 2015
|
|
13
|
|
|
|
|
94
|
|
|
|
||||||
Canadian operations (3)
|
Assets held for sale
|
|
NGL & Petchem Services
|
|
June 30, 2016
|
|
924
|
|
|
$
|
341
|
|
|
|
|
|
|||||
Certain gathering operations (4)
|
Property, plant, and equipment – net
|
|
Central
|
|
June 30, 2016
|
|
18
|
|
|
48
|
|
|
|
|
|
||||||
Level 3 fair value measurements of certain assets
|
|
|
|
|
|
|
|
|
389
|
|
|
114
|
|
|
42
|
|
|||||
Other impairments and write-downs (5)
|
|
|
|
|
|
|
|
|
68
|
|
|
31
|
|
|
10
|
|
|||||
Impairment of certain assets
|
|
|
|
|
|
|
|
|
$
|
457
|
|
|
$
|
145
|
|
|
$
|
52
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Equity-method investments (6)
|
Investments
|
|
Central and Northeast G&P
|
|
September 30, 2015
|
|
$
|
1,203
|
|
|
|
|
$
|
461
|
|
|
|
||||
Equity-method investments (7)
|
Investments
|
|
Central and Northeast G&P
|
|
December 31, 2015
|
|
4,017
|
|
|
|
|
890
|
|
|
|
||||||
Equity-method investments (8)
|
Investments
|
|
Central and Northeast G&P
|
|
March 31, 2016
|
|
1,294
|
|
|
$
|
109
|
|
|
|
|
|
|||||
Equity-method investments (9)
|
Investments
|
|
Central and Northeast G&P
|
|
December 31, 2016
|
|
1,295
|
|
|
318
|
|
|
|
|
|
||||||
Other equity-method investment
|
Investments
|
|
NGL & Petchem Services
|
|
December 31, 2015
|
|
58
|
|
|
|
|
8
|
|
|
|
||||||
Other equity-method investment
|
Investments
|
|
Central
|
|
March 31, 2016
|
|
—
|
|
|
3
|
|
|
|
|
|
||||||
Impairment of equity-method investments
|
|
|
|
|
|
|
|
|
$
|
430
|
|
|
$
|
1,359
|
|
|
|
(1)
|
Relates to certain surplus equipment. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market.
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
(2)
|
Relates to a gas processing plant, the completion of which is considered remote due to unfavorable impact of low natural gas prices on customer drilling activities. 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.
|
(3)
|
Relates to our Canadian operations. We designated these operations as held for sale as of June 30, 2016. As a result, we measured the fair value of the disposal group, resulting in an impairment charge. The estimated fair value was determined by a market approach based primarily on inputs received in the marketing process and reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale during the third quarter of 2016. See
Note 3 – Divestiture
.
|
(4)
|
Relates to certain gathering assets within the Mid-Continent region. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market.
|
(5)
|
Reflects multiple individually insignificant impairments and write-downs 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.
|
(6)
|
Relates to equity-method investments in DBJV at Central and certain of the Appalachia Midstream Investments at Northeast G&P. 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 acquisition of ACMP. 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 DBJV 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.
|
(7)
|
Relates to equity-method investments in DBJV at Central and Northeast G&P’s UEOM and Laurel Mountain investments, as well as certain of the Appalachia Midstream Investments. 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 2015 increases in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.
|
(8)
|
Relates to Central’s equity-method investment in DBJV and Northeast G&P’s equity-method investment in Laurel Mountain. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates for both of these investments, along with lower natural gas prices for Laurel Mountain. 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
13.0 percent
to
13.3 percent
and reflected increases in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.
|
(9)
|
Relates to equity-method investments in Ranch Westex at Central and multiple Appalachia Midstream Investments at Northeast G&P. 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 acquisition of ACMP. We estimated the fair value of these Appalachia Midstream 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, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was
10.2 percent
and reflected our cost of capital as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an income approach, we
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
NGLs, natural gas, and related products and services
|
$
|
736
|
|
|
$
|
821
|
|
Transportation of natural gas and related products
|
187
|
|
|
202
|
|
||
Other
|
3
|
|
|
3
|
|
||
Total
|
$
|
926
|
|
|
$
|
1,026
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
•
|
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.
|
|
|
|
United States
|
|
Canada
|
|
Total
|
||||||
|
|
|
(Millions)
|
||||||||||
Revenues from external customers:
|
|
|
|
|
|
|
|||||||
|
2016
|
|
$
|
7,406
|
|
|
$
|
85
|
|
|
$
|
7,491
|
|
|
2015
|
|
7,228
|
|
|
103
|
|
|
7,331
|
|
|||
|
2014
|
|
7,212
|
|
|
197
|
|
|
7,409
|
|
|||
|
|
|
|
|
|
|
|
||||||
Long-lived assets:
|
|
|
|
|
|
|
|||||||
|
2016
|
|
$
|
37,683
|
|
|
$
|
—
|
|
|
$
|
37,683
|
|
|
2015
|
|
37,586
|
|
|
1,030
|
|
|
38,616
|
|
|||
|
2014
|
|
37,798
|
|
|
1,095
|
|
|
38,893
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
Central
|
|
Northeast
G&P
|
|
Atlantic-
Gulf
|
|
West
|
|
NGL &
Petchem
Services
|
|
Eliminations
|
|
Total
|
||||||||||||||
|
(Millions)
|
||||||||||||||||||||||||||
2016
|
|||||||||||||||||||||||||||
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Service revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
External
|
$
|
1,228
|
|
|
$
|
804
|
|
|
$
|
1,939
|
|
|
$
|
1,034
|
|
|
$
|
168
|
|
|
$
|
—
|
|
|
$
|
5,173
|
|
Internal
|
13
|
|
|
34
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
(60
|
)
|
|
—
|
|
|||||||
Total service revenues
|
1,241
|
|
|
838
|
|
|
1,952
|
|
|
1,034
|
|
|
168
|
|
|
(60
|
)
|
|
5,173
|
|
|||||||
Product sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
External
|
—
|
|
|
135
|
|
|
244
|
|
|
18
|
|
|
1,921
|
|
|
—
|
|
|
2,318
|
|
|||||||
Internal
|
—
|
|
|
28
|
|
|
205
|
|
|
260
|
|
|
181
|
|
|
(674
|
)
|
|
—
|
|
|||||||
Total product sales
|
—
|
|
|
163
|
|
|
449
|
|
|
278
|
|
|
2,102
|
|
|
(674
|
)
|
|
2,318
|
|
|||||||
Total revenues
|
$
|
1,241
|
|
|
$
|
1,001
|
|
|
$
|
2,401
|
|
|
$
|
1,312
|
|
|
$
|
2,270
|
|
|
$
|
(734
|
)
|
|
$
|
7,491
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Proportional Modified EBITDA of equity-method investments
|
$
|
48
|
|
|
$
|
362
|
|
|
$
|
287
|
|
|
$
|
—
|
|
|
$
|
57
|
|
|
$
|
—
|
|
|
$
|
754
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
2015
|
|
|
|
|
|||||||||||||||||||||||
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Service revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
External
|
$
|
1,261
|
|
|
$
|
803
|
|
|
$
|
1,877
|
|
|
$
|
1,055
|
|
|
$
|
139
|
|
|
$
|
—
|
|
|
$
|
5,135
|
|
Internal
|
26
|
|
|
7
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
(37
|
)
|
|
—
|
|
|||||||
Total service revenues
|
1,287
|
|
|
810
|
|
|
1,881
|
|
|
1,055
|
|
|
139
|
|
|
(37
|
)
|
|
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
|
$
|
1,287
|
|
|
$
|
937
|
|
|
$
|
2,344
|
|
|
$
|
1,312
|
|
|
$
|
2,060
|
|
|
$
|
(609
|
)
|
|
$
|
7,331
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Proportional Modified EBITDA of equity-method investments
|
$
|
36
|
|
|
$
|
349
|
|
|
$
|
257
|
|
|
$
|
—
|
|
|
$
|
42
|
|
|
$
|
15
|
|
|
$
|
699
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Service revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
External
|
$
|
666
|
|
|
$
|
549
|
|
|
$
|
1,497
|
|
|
$
|
1,050
|
|
|
$
|
126
|
|
|
$
|
—
|
|
|
$
|
3,888
|
|
Internal
|
12
|
|
|
1
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
|
—
|
|
|||||||
Total service revenues
|
678
|
|
|
550
|
|
|
1,501
|
|
|
1,050
|
|
|
126
|
|
|
(17
|
)
|
|
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
|
$
|
678
|
|
|
$
|
780
|
|
|
$
|
2,354
|
|
|
$
|
1,596
|
|
|
$
|
3,112
|
|
|
$
|
(1,111
|
)
|
|
$
|
7,409
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Proportional Modified EBITDA of equity-method investments
|
$
|
25
|
|
|
$
|
198
|
|
|
$
|
151
|
|
|
$
|
—
|
|
|
$
|
50
|
|
|
$
|
7
|
|
|
$
|
431
|
|
Williams Partners L.P.
|
||
Notes to Consolidated Financial Statements – (Continued)
|
||
|
|
Years Ended December 31,
|
||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||||||||
|
|
|
|
|
(Millions)
|
||||||||||||
Modified EBITDA by segment:
|
|
|
|
|
|
||||||||||||
Central
|
$
|
807
|
|
|
$
|
840
|
|
|
$
|
419
|
|
||||||
Northeast G&P
|
840
|
|
|
753
|
|
|
618
|
|
|||||||||
Atlantic-Gulf
|
1,600
|
|
|
1,523
|
|
|
1,065
|
|
|||||||||
West
|
649
|
|
|
557
|
|
|
823
|
|
|||||||||
NGL & Petchem Services
|
(23
|
)
|
|
321
|
|
|
324
|
|
|||||||||
Other
|
(9
|
)
|
|
9
|
|
|
(5
|
)
|
|||||||||
|
3,864
|
|
|
4,003
|
|
|
3,244
|
|
|||||||||
Accretion expense associated with asset retirement obligations for nonregulated operations
|
(31
|
)
|
|
(28
|
)
|
|
(17
|
)
|
|||||||||
Depreciation and amortization expenses
|
(1,720
|
)
|
|
(1,702
|
)
|
|
(1,151
|
)
|
|||||||||
Impairment of goodwill
|
—
|
|
|
(1,098
|
)
|
|
—
|
|
|||||||||
Equity earnings (losses)
|
397
|
|
|
335
|
|
|
228
|
|
|||||||||
Impairment of equity-method investments
|
(430
|
)
|
|
(1,359
|
)
|
|
—
|
|
|||||||||
Other investing income (loss) – net
|
29
|
|
|
2
|
|
|
2
|
|
|||||||||
Proportional Modified EBITDA of equity-method investments
|
(754
|
)
|
|
(699
|
)
|
|
(431
|
)
|
|||||||||
Interest expense
|
(916
|
)
|
|
(811
|
)
|
|
(562
|
)
|
|||||||||
(Provision) benefit for income taxes
|
80
|
|
|
(1
|
)
|
|
(29
|
)
|
|||||||||
Net income (loss)
|
$
|
519
|
|
|
$
|
(1,358
|
)
|
|
$
|
1,284
|
|
|
Total Assets at December 31,
|
|
Investments at December 31,
|
|
Additions to Long-Lived Assets at December 31,
|
||||||||||||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||||
|
(Millions)
|
||||||||||||||||||||||||||
Central (1)
|
$
|
13,129
|
|
|
$
|
13,914
|
|
|
$
|
1,033
|
|
|
$
|
1,050
|
|
|
$
|
88
|
|
|
$
|
363
|
|
|
$
|
13,016
|
|
Northeast G&P (1)
|
13,324
|
|
|
13,827
|
|
|
4,289
|
|
|
4,823
|
|
|
217
|
|
|
560
|
|
|
4,497
|
|
|||||||
Atlantic-Gulf
|
13,892
|
|
|
12,171
|
|
|
893
|
|
|
959
|
|
|
1,590
|
|
|
1,573
|
|
|
1,593
|
|
|||||||
West (1)
|
4,715
|
|
|
5,035
|
|
|
—
|
|
|
—
|
|
|
124
|
|
|
225
|
|
|
698
|
|
|||||||
NGL & Petchem Services
|
2,304
|
|
|
3,306
|
|
|
486
|
|
|
504
|
|
|
83
|
|
|
236
|
|
|
601
|
|
|||||||
Other corporate assets
|
207
|
|
|
350
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
8
|
|
|||||||
Eliminations (2)
|
(1,306
|
)
|
|
(733
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Total
|
$
|
46,265
|
|
|
$
|
47,870
|
|
|
$
|
6,701
|
|
|
$
|
7,336
|
|
|
$
|
2,102
|
|
|
$
|
2,960
|
|
|
$
|
20,413
|
|
|
(1)
|
2014
Additions to long-lived assets
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.
|
Williams Partners L.P.
|
||
Quarterly Financial Data
|
||
(Unaudited)
|
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
|
|
(Millions, except per-unit amounts)
|
||||||||||||||
2016
|
|
|
|
|
|
|
|
|
||||||||
Revenues (1)
|
|
$
|
1,654
|
|
|
$
|
1,740
|
|
|
$
|
1,907
|
|
|
$
|
2,190
|
|
Product costs (1)
|
|
317
|
|
|
403
|
|
|
463
|
|
|
545
|
|
||||
Net income (loss)
|
|
79
|
|
|
(77
|
)
|
|
351
|
|
|
166
|
|
||||
Net income (loss) attributable to controlling interests
|
|
50
|
|
|
(90
|
)
|
|
326
|
|
|
145
|
|
||||
Net income (loss) allocated to common units for calculation of earnings per common unit (2)
|
|
(148
|
)
|
|
(289
|
)
|
|
247
|
|
|
143
|
|
||||
Basic and diluted net income (loss) per common unit (3)
|
|
(.25
|
)
|
|
(.49
|
)
|
|
.42
|
|
|
.24
|
|
||||
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 (2)
|
|
(172
|
)
|
|
83
|
|
|
(190
|
)
|
|
(1,577
|
)
|
||||
Basic and diluted net income (loss) per common unit (3)
|
|
(.34
|
)
|
|
.14
|
|
|
(.32
|
)
|
|
(2.68
|
)
|
(1)
|
Amounts reported for second quarter 2016 have been adjusted to reflect the presentation of certain revenues and costs on a gross basis. These adjustments increased previously reported
Revenues
and
Product costs
by $10 million, with no impact on
Operating income (loss)
.
|
(2)
|
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.
|
(3)
|
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.
|
•
|
$173 million of income associated with the amortization of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-Continent regions and $58 million of related minimum volume commitment fees (see
Note 8 – Other Income and Expenses
of Notes to Consolidated Financial Statements);
|
•
|
$318 million impairment loss on certain equity-method investments (see
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
).
|
Williams Partners L.P.
|
||
Quarterly Financial Data – (Continued)
|
||
(Unaudited)
|
•
|
$239 million in revenue associated with minimum volume commitment fees in the Barnett Shale and Mid-Continent regions (see
Note 8 – Other Income and Expenses
);
|
•
|
$116 million impairment loss on certain assets (see
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
);
|
•
|
$898 million impairment loss on certain equity-method investments (see
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
);
|
•
|
$1,098 million impairment of goodwill (see
Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
).
|
Name
|
|
Age
|
|
Position with Williams Partners GP LLC
|
Alan S. Armstrong
|
|
54
|
|
Chairman of the Board and Chief Executive Officer
|
Donald R. Chappel
|
|
65
|
|
Chief Financial Officer and Director
|
Rory L. Miller
|
|
56
|
|
Senior Vice President - Atlantic-Gulf and Director
|
James E. Scheel
|
|
52
|
|
Senior Vice President - Northeast G&P and Director
|
H. Brent Austin
|
|
62
|
|
Director and Member of Audit and Conflicts Committees
|
Alice M. Peterson
|
|
64
|
|
Director and Member of Audit and Conflicts Committees
|
Philip L. Frederickson
|
|
60
|
|
Director and Member of Audit and Conflicts Committees
|
Frank E. Billings
|
|
54
|
|
Senior Vice President - Corporate Strategic Development
|
Walter J. Bennett
|
|
47
|
|
Senior Vice President - West and Director
|
John R. Dearborn
|
|
59
|
|
Senior Vice President - NGL & Petchem Services
|
John D. Seldenrust
|
|
52
|
|
Senior Vice President - Engineering Services
|
Sarah C. Miller
|
|
45
|
|
Senior Vice President and General Counsel
|
Ted T. Timmermans
|
|
60
|
|
Vice President, Controller, and Chief Accounting Officer
|
•
|
Industry Experience in the oil, natural gas, and petrochemicals business.
|
•
|
Engineering and Construction Experience.
|
•
|
Financial and Accounting Experience.
|
•
|
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).
|
|
Audit
|
|
Conflicts
|
|
Committee
|
|
Committee
|
H. Brent Austin
|
ü
|
|
•
|
Philip L. Frederickson
|
ü
|
|
ü
|
Alice M. Peterson
|
•
|
|
ü
|
•
|
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, 2016, for filing with the SEC.
|
Name and
Principal Position
|
Year
|
Salary
|
Bonus
|
Stock Awards (1)
|
Option Awards (2)
|
Non-Equity Incentive Plan Compensation (3)
|
Change in Pension Value and Nonqualified Deferred Compensation Earnings (4)
|
All Other Compensation (5)
|
Total
|
||||||||||||||||
Alan S. Armstrong
|
2016
|
$
|
1,104,619
|
|
$
|
—
|
|
$
|
5,198,012
|
|
$
|
1,134,671
|
|
$
|
1,863,824
|
|
$
|
665,884
|
|
$
|
23,706
|
|
$
|
9,990,716
|
|
President and Chief
|
2015
|
1,100,925
|
|
—
|
|
4,024,297
|
|
1,152,621
|
|
1,128,905
|
|
(568,869
|
)
|
40,772
|
|
6,878,652
|
|
||||||||
Executive Officer
|
2014
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
||||||||
Donald R. Chappel
|
2016
|
658,150
|
|
—
|
|
1,764,641
|
|
394,301
|
|
687,347
|
|
314,266
|
|
20,681
|
|
3,839,386
|
|
||||||||
SVP, Chief Financial
|
2015
|
658,534
|
|
—
|
|
1,433,184
|
|
400,993
|
|
598,224
|
|
(253,539
|
)
|
20,159
|
|
2,857,555
|
|
||||||||
Officer
|
2014
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
||||||||
John D. Seldenrust
|
2016
|
457,547
|
|
—
|
|
1,330,020
|
|
297,183
|
|
940,766
|
|
174,407
|
|
17,096
|
|
3,217,019
|
|
||||||||
SVP, Engineering
|
2015
|
429,579
|
|
—
|
|
1,137,565
|
|
93,743
|
|
707,231
|
|
55,545
|
|
22,046
|
|
2,445,708
|
|
||||||||
Services
|
2014
|
390,454
|
|
371,241
|
|
5,102,763
|
|
—
|
|
—
|
|
—
|
|
163,446
|
|
6,027,904
|
|
||||||||
Rory L. Miller
|
2016
|
490,000
|
|
—
|
|
1,342,640
|
|
300,003
|
|
486,000
|
|
224,134
|
|
17,288
|
|
2,860,065
|
|
||||||||
SVP, Atlantic - Gulf
|
2015
|
487,692
|
|
—
|
|
1,086,877
|
|
304,088
|
|
310,000
|
|
(201,730
|
)
|
16,848
|
|
2,003,775
|
|
||||||||
|
2014
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
||||||||
James E. Scheel
|
2016
|
446,000
|
|
—
|
|
1,342,640
|
|
300,003
|
|
450,000
|
|
185,458
|
|
18,497
|
|
2,742,598
|
|
||||||||
SVP, Northeast G&P
|
2015
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
||||||||
|
2014
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(1)
|
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 Compensation - Stock Compensation (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, 2016.
|
(2)
|
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, 2016. The options may be exercised to acquire Williams’ common stock. The NEOs do not receive any option awards from us.
|
(3)
|
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 245 percent of target and the amounts shown are costs attributable to us. We do not sponsor any non-equity incentive plans. Mr. Seldenrust’s 2016 and 2015 amounts include special engineering and construction incentive awards of $500,000 in each year.
|
(4)
|
Change in Pension Value and Nonqualified Deferred Compensation Earnings.
The amount shown is the aggregate change attributable to us from December 31, 2015 to December 31, 2016 in the actuarial present value of the accrued benefit under the qualified pension and non-qualified plan. The primary reason for the increase in the change in present value is a lower discount rate used to measure these benefits at the end of 2016. The underlying design of these programs did not change from 2015 to 2016. Please refer to the “Pension Benefits” table in Williams’ Proxy Statement for further details of the present value of the accrued benefit.
|
(5)
|
All Other Compensation.
Amounts shown represent payments attributable to us 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 are not included because the individual aggregate amounts do not 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.
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Seldenrust
|
|
|
|
|
|
|
|
7/16/2014
|
|
|
53,998
|
|
$
|
2,053,544
|
|
Miller
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Scheel
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
The time-based WPZ RSU award granted to Mr. Seldenrust on July 16, 2014 is on a four-year graded vesting schedule. The first 18.75 percent vested on July 16, 2016, the second 18.75 percent will vest on July 16, 2017, with the final 62.50 percent vesting on July 16, 2018. This award was 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)
|
Based on a closing WPZ stock price of $38.03 on December 31, 2016.
|
Name
|
|
Fees Earned or 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
|
|
$
|
182,500
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
182,500
|
|
David Daberko (2)
|
|
22,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22,500
|
|
|||||||
Phil Frederickson
|
|
172,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
172,500
|
|
|||||||
Alice M. Peterson
|
|
182,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
182,500
|
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Bi-annual compensation retainer fees and Conflicts Committee meeting fees paid in 2016 are reflected in this column.
|
(2)
|
Mr. Daberko resigned from the Board effective December 3, 2015. The $22,500 of fees shown in the table above were earned in 2015 by Mr. Daberko while serving as a member of the Conflicts Committee of WPZ but paid in 2016.
|
•
|
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;
|
•
|
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.
|
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)
|
|
702,218,502
|
|
|
73.50%
|
|
17,065,816
|
|
|
100.00%
|
Alan S. Armstrong (3)
|
|
32,334
|
|
|
*
|
|
—
|
|
|
—
|
H. Brent Austin
|
|
8,958
|
|
|
*
|
|
—
|
|
|
—
|
Walter J. Bennett
|
|
8,770
|
|
|
*
|
|
—
|
|
|
—
|
Donald R. Chappel
|
|
19,574
|
|
|
*
|
|
—
|
|
|
—
|
Philip L. Frederickson
|
|
23,577
|
|
|
*
|
|
—
|
|
|
—
|
Rory L. Miller
|
|
1,752
|
|
|
*
|
|
—
|
|
|
—
|
Alice M. Peterson
|
|
3,921
|
|
|
*
|
|
—
|
|
|
—
|
James E. Scheel
|
|
—
|
|
|
*
|
|
—
|
|
|
—
|
John D. Seldenrust
|
|
1,262
|
|
|
*
|
|
—
|
|
|
—
|
All executive officers and directors of general partner as a group (13 persons)
|
|
100,726
|
|
|
*
|
|
—
|
|
|
—
|
(1)
|
The percentage of beneficial ownership is based on 955,446,491 common units outstanding as of February 17, 2017.
|
(2)
|
This row includes ownership information of Williams Gas Pipeline Company, LLC, which is controlled by Williams and directly held 702,218,502 Common Units and 17,065,816 Class B Units as of February 17, 2017.
|
(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)
|
|
304,734
|
|
|
911,746
|
|
|
31,422
|
|
|
1,247,902
|
|
|
*
|
H. Brent Austin
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
*
|
Walter J. Bennett
|
|
—
|
|
|
33,969
|
|
|
—
|
|
|
33,969
|
|
|
*
|
Donald R. Chappel
|
|
310,991
|
|
|
724,956
|
|
|
37,869
|
|
|
1,073,816
|
|
|
*
|
Philip L. Frederickson
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
*
|
Rory L. Miller
|
|
80,300
|
|
|
251,663
|
|
|
25,889
|
|
|
357,852
|
|
|
*
|
Alice M. Peterson
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
*
|
James E. Scheel (5)
|
|
20,116
|
|
|
171,306
|
|
|
10,055
|
|
|
201,477
|
|
|
*
|
John D. Seldenrust
|
|
—
|
|
|
20,910
|
|
|
—
|
|
|
20,910
|
|
|
*
|
All current directors and executive officers as a group (22 persons)
|
|
959,936
|
|
|
2,699,121
|
|
|
163,891
|
|
|
3,822,948
|
|
|
*
|
*
|
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 17, 2017.
|
(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 17, 2017. Restricted stock units have no voting or investment power.
|
(3)
|
Ownership percentage is reported based on 955,446,491 shares of Williams common stock outstanding on February 17, 2017, 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 17, 2017 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.
|
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)
|
|
558,868
|
|
|
N/A
|
|
1,588,484
|
|
(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.
|
(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, 2016, 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, 2016.
|
|
|
Operational Stage
|
|
|
|
Distributions of available cash to our general partner and its affiliate
|
|
Prior to the 2017 transactions discussed above, we generally made cash distributions 98 percent to our unitholders pro rata, including Williams as the holder of an aggregate 58 percent of common units and 2 percent to our general partner.
|
|
|
|
|
|
In addition, if distributions exceeded the minimum quarterly distribution and other higher target distribution levels, our general partner was entitled to increasing percentages of the distributions, up to 50 percent of the distributions above the highest target distribution level. We refer to the rights to the increasing distributions as “incentive distribution rights.”
|
|
|
|
|
|
Our general partner previously agreed to temporarily waive a portion of 2016 incentive distributions in connection with the execution of the Termination Agreement and the sale of Canadian operations.
|
|
|
|
|
|
As a result of the 2017 transactions discussed above, our general partner will no longer receive cash distributions in respect of its general partner interest or incentive distributions. We will only make cash distributions to our unit holders pro rata including to Williams as the holder of an aggregate 74 percent of our common units. However, with respect to the approximately 59 million common units issued to Williams in the 2017 private placement, Williams is not entitled to receive distributions on such common units for the quarter ended December 31, 2016 and the prorated portion of the first quarter of 2017 up to closing of the private placement. 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 will either be sold to the new general partner for cash or converted into common units, for an amount equal to fair market value.
|
|
|
|
|
|
Liquidation Stage
|
|
|
|
Liquidation
|
|
Upon our liquidation, the limited partners will be entitled to receive liquidating distributions according to their particular capital account balances.
|
•
|
Indemnification for certain environmental liabilities and tax liabilities;
|
•
|
Reimbursement for certain expenditures;
|
•
|
A license for the use of certain software and intellectual property.
|
•
|
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
|
•
|
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.
|
|
2016
|
|
2015
|
||||
|
(Millions)
|
||||||
Audit Fees
|
$
|
5.7
|
|
|
$
|
6.6
|
|
Audit-Related Fees
|
0.4
|
|
|
0.4
|
|
||
Tax Fees
|
0.1
|
|
|
—
|
|
||
All Other Fees
|
—
|
|
|
—
|
|
||
|
$
|
6.2
|
|
|
$
|
7.0
|
|
|
Page
|
Covered by reports of independent auditors:
|
|
Not covered by reports of independent auditors:
|
|
(a)
|
3 and (b). The following documents are included as exhibits to this report:
|
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).
|
|
|
|
|
|
2.2
|
|
—
|
|
Share Purchase Agreement by and between Williams Energy Canada LP and Inter Pipeline Ltd. and Williams Partners L.P., dated August 8, 2016 (filed on August 12, 2016 as Exhibit 2.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
|
|
|
|
|
|
2.3§
|
|
—
|
|
Interest Swap and Purchase Agreement by and among Western Gas Partners, LP, WGR Operating, LP, Delaware Basin JV Gathering LLC, Williams Partners L.P., Williams Midstream Gas Services LLC, and Appalachia Midstream Services, L.L.C., dated February 9, 2017 (filed on February 10, 2017 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).
|
|
|
|
|
|
Exhibit
Number
|
|
|
|
Description
|
|
|
|
|
|
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
|
|
—
|
|
Amendment No. 7 to the First Amended and Restated Agreement of Limited Partnership of Williams Partners L.P., dated October 12, 2016 (filed on October 13, 2016 as Exhibit 3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
|
|
|
|
|
|
3.13
|
|
—
|
|
Amendment No. 8 to the First Amended and Restated Agreement of Limited Partnership of Williams Partners L.P., dated January 9, 2017 (filed on January 10, 2017 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).
|
|
|
|
|
|
3.14*
|
|
—
|
|
Composite Agreement of Limited Partnership of Williams Partners L.P.
|
|
|
|
|
|
3.15
|
|
—
|
|
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).
|
|
|
|
|
|
3.16
|
|
—
|
|
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).
|
|
|
|
|
|
3.17
|
|
—
|
|
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).
|
|
|
|
|
|
3.18
|
|
—
|
|
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).
|
Exhibit
Number
|
|
|
|
Description
|
|
|
|
|
|
|
|
|
|
|
3.19
|
|
—
|
|
Eighth Amended and Restated Limited Liability Company Agreement of WPZ GP LLC (filed on August 2, 2016 as Exhibit 3.17 to Williams Partners L.P.’s quarterly report on Form 10-Q (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).
|
|
|
|
|
|
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).
|
|
|
|
|
|
Exhibit
Number
|
|
|
|
Description
|
|
|
|
|
|
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).
|
|
|
|
|
|
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).
|
|
|
|
|
|
Exhibit
Number
|
|
|
|
Description
|
|
|
|
|
|
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).
|
|
|
|
|
|
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).
|
Exhibit
Number
|
|
|
|
Description
|
|
|
|
|
|
|
|
|
|
|
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
|
|
—
|
|
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).
|
|
|
|
|
|
10.15
|
|
—
|
|
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).
|
|
|
|
|
|
10.16
|
|
—
|
|
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).
|
|
|
|
|
|
Exhibit
Number
|
|
|
|
Description
|
|
|
|
|
|
10.17
|
|
—
|
|
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).
|
|
|
|
|
|
10.18
|
|
—
|
|
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).
|
|
|
|
|
|
10.19
|
|
—
|
|
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).
|
|
|
|
|
|
10.20
|
|
—
|
|
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 Form 8-K (File No. 001-34831) and incorporated herein by reference).
|
|
|
|
|
|
10.21
|
|
—
|
|
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. (filed on February 26, 2016 as Exhibit 10.22 to Williams Partners L.P.’s annual report on Form 10-K (file No. 001-34831) and incorporated herein by reference).
|
|
|
|
|
|
10.22
|
|
—
|
|
Second Amendment to Equity Distribution Agreement dated February 29, 2016, 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 May 5, 2016 as Exhibit 10.2 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
|
|
|
|
|
|
10.23
|
|
—
|
|
Third Amendment to Equity Distribution Agreement dated August 2, 2016, 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 MUFG Securities Americas Inc. (filed on October 31, 2016 as Exhibit 10.2 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
|
|
|
|
|
|
10.24
|
|
—
|
|
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 current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
|
|
|
|
|
|
10.25
|
|
—
|
|
Common Unit Issuance Agreement, dated January 9, 2017 (filed on January 10, 2017 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).
|
|
|
|
|
|
10.26
|
|
—
|
|
Common Unit Purchase Agreement, dated January 9, 2017 (filed on January 10, 2017 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).
|
|
|
|
|
|
12*
|
|
—
|
|
Computation of Ratio of Earnings to Fixed Charges.
|
|
|
|
|
|
21*
|
|
—
|
|
List of subsidiaries of Williams Partners L.P.
|
|
|
|
|
|
Exhibit
Number
|
|
|
|
Description
|
|
|
|
|
|
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.
|
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)
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ ALAN S. ARMSTRONG
|
|
Chief Executive Officer and
|
|
February 22, 2017
|
Alan S. Armstrong
|
|
Chairman of the Board (Principal
Executive Officer)
|
|
|
|
|
|
|
|
/s/ DONALD R. CHAPPEL
|
|
Chief Financial Officer and Director
|
|
February 22, 2017
|
Donald R. Chappel
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
/s/ TED T. TIMMERMANS
|
|
Vice President, Controller, and Chief
|
|
February 22, 2017
|
Ted T. Timmermans
|
|
Accounting Officer
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
/s/ H. BRENT AUSTIN*
|
|
Director
|
|
February 22, 2017
|
H. Brent Austin
|
|
|
|
|
|
|
|
|
|
/s/ WALTER J. BENNETT*
|
|
Director
|
|
February 22, 2017
|
Walter J. Bennett
|
|
|
|
|
|
|
|
|
|
/s/ PHILIP L. FREDERICKSON*
|
|
Director
|
|
February 22, 2017
|
Philip L. Frederickson
|
|
|
|
|
|
|
|
|
|
/s/ RORY L. MILLER*
|
|
Director
|
|
February 22, 2017
|
Rory L. Miller
|
|
|
|
|
|
|
|
|
|
/s/ ALICE M. PETERSON*
|
|
Director
|
|
February 22, 2017
|
Alice M. Peterson
|
|
|
|
|
|
|
|
|
|
/s/ JAMES E. SCHEEL*
|
|
Director
|
|
February 22, 2017
|
James E. Scheel
|
|
|
|
|
|
|
|
|
|
*By:
/s/ Sarah C. Miller
|
|
|
|
February 22, 2017
|
Sarah C. Miller
Attorney-in-fact
|
|
|
|
|
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).
|
|
|
|
|
|
2.2
|
|
—
|
|
Share Purchase Agreement by and between Williams Energy Canada LP and Inter Pipeline Ltd. and Williams Partners L.P., dated August 8, 2016 (filed on August 12, 2016 as Exhibit 2.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
|
|
|
|
|
|
2.3§
|
|
—
|
|
Interest Swap and Purchase Agreement by and among Western Gas Partners, LP, WGR Operating, LP, Delaware Basin JV Gathering LLC, Williams Partners L.P., Williams Midstream Gas Services LLC, and Appalachia Midstream Services, L.L.C., dated February 9, 2017 (filed on February 10, 2017 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).
|
|
|
|
|
|
Exhibit
Number
|
|
|
|
Description
|
|
|
|
|
|
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
|
|
—
|
|
Amendment No. 7 to the First Amended and Restated Agreement of Limited Partnership of Williams Partners L.P., dated October 12, 2016 (filed on October 13, 2016 as Exhibit 3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
|
|
|
|
|
|
3.13
|
|
—
|
|
Amendment No. 8 to the First Amended and Restated Agreement of Limited Partnership of Williams Partners L.P., dated January 9, 2017 (filed on January 10, 2017 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).
|
|
|
|
|
|
3.14*
|
|
—
|
|
Composite Agreement of Limited Partnership of Williams Partners L.P.
|
|
|
|
|
|
3.15
|
|
—
|
|
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).
|
|
|
|
|
|
3.16
|
|
—
|
|
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).
|
|
|
|
|
|
3.17
|
|
—
|
|
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).
|
|
|
|
|
|
3.18
|
|
—
|
|
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).
|
|
|
|
|
|
3.19
|
|
—
|
|
Eighth Amended and Restated Limited Liability Company Agreement of WPZ GP LLC (filed on August 2, 2016 as Exhibit 3.17 to Williams Partners L.P.’s quarterly report on Form 10-Q (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).
|
|
|
|
|
|
Exhibit
Number
|
|
|
|
Description
|
|
|
|
|
|
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).
|
|
|
|
|
|
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).
|
|
|
|
|
|
Exhibit
Number
|
|
|
|
Description
|
|
|
|
|
|
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).
|
|
|
|
|
|
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).
|
Exhibit
Number
|
|
|
|
Description
|
|
|
|
|
|
|
|
|
|
|
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).
|
|
|
|
|
|
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).
|
Exhibit
Number
|
|
|
|
Description
|
|
|
|
|
|
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
|
|
—
|
|
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).
|
|
|
|
|
|
10.15
|
|
—
|
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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).
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10.16
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—
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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).
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10.17
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—
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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).
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10.18
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—
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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).
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10.19
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—
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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).
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10.20
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—
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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 Form 8-K (File No. 001-34831) and incorporated herein by reference).
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10.21
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—
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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. (filed on February 26, 2016 as Exhibit 10.22 to Williams Partners L.P.’s annual report on Form 10-K (file No. 001-34831) and incorporated herein by reference).
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10.22
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—
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Second Amendment to Equity Distribution Agreement dated February 29, 2016, 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 May 5, 2016 as Exhibit 10.2 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
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Exhibit
Number
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Description
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10.23
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—
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Third Amendment to Equity Distribution Agreement dated August 2, 2016, 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 MUFG Securities Americas Inc. (filed on October 31, 2016 as Exhibit 10.2 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
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10.24
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—
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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 current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
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10.25
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—
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Common Unit Issuance Agreement, dated January 9, 2017 (filed on January 10, 2017 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).
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10.26
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—
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Common Unit Purchase Agreement, dated January 9, 2017 (filed on January 10, 2017 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).
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12*
|
|
—
|
|
Computation of Ratio of Earnings to Fixed Charges.
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21*
|
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—
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|
List of subsidiaries of Williams Partners L.P.
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23.1*
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—
|
|
Consent of Ernst & Young LLP.
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23.2*
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—
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|
Consent of Deloitte & Touche LLP.
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24*
|
|
—
|
|
Power of attorney.
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31.1*
|
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—
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
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31.2*
|
|
—
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
|
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|
|
32**
|
|
—
|
|
Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.
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|
|
101.INS*
|
|
—
|
|
XBRL Instance Document.
|
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|
101.SCH*
|
|
—
|
|
XBRL Taxonomy Extension Schema.
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|
101.CAL*
|
|
—
|
|
XBRL Taxonomy Extension Calculation Linkbase.
|
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|
101.DEF*
|
|
—
|
|
XBRL Taxonomy Extension Definition Linkbase.
|
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|
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|
101.LAB*
|
|
—
|
|
XBRL Taxonomy Extension Label Linkbase.
|
|
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|
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|
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.
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