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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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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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Delaware
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26-1075808
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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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1201 Lake Robbins Drive
The Woodlands, Texas
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77380
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(Address of principal executive offices)
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(Zip Code)
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Title of Each Class
Common Units Representing Limited Partner Interests
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Name of Each Exchange on Which Registered
New York Stock Exchange
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Large accelerated filer
☑
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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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Item
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Page
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1 and 2.
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1A.
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1B.
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3.
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4.
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5.
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6.
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7.
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7A.
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8.
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9.
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9A.
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9B.
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Item
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Page
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10.
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11.
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12.
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13.
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14.
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15.
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Owned and
Operated
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Operated
Interests
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Non-Operated
Interests
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Equity Interests
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Natural gas gathering systems
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12
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2
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5
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2
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Natural gas treating facilities
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12
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4
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—
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3
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Natural gas processing plants/trains
(1)
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18
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5
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—
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2
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NGL pipelines
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2
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—
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—
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3
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Natural gas pipelines
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4
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—
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—
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—
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Oil pipeline
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—
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—
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—
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1
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(1)
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On December 3, 2015, an incident occurred at our DBM complex. See
General Trends and Outlook
, under Part II, Item 7 of this Form 10-K.
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Area
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Asset Type
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Miles of Pipeline
(1)
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Approximate Number of Active Receipt Points
(1)
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Compression (HP)
(1)
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Processing or Treating Capacity (MMcf/d)
(1) (2)
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Average Gathering, Processing and Transportation Throughput (MMcf/d)
(3)
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Average Gathering, Processing and Transportation Throughput (MBbls/d)
(4)
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Rocky Mountains
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Gathering, Processing and Treating
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7,336
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4,883
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551,898
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3,384
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2,388
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—
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Transportation
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1,732
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55
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41,968
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—
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105
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33
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Mid-Continent
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Gathering
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2,097
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1,472
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90,214
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—
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61
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—
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North-central Pennsylvania
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Gathering
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672
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387
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76,900
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—
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752
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—
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Texas
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Gathering, Processing and Treating
(5)
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989
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681
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181,965
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820
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690
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—
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Transportation
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1,154
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13
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40,895
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—
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—
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105
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Total
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13,980
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7,491
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983,840
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4,204
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3,996
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138
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(1)
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All system metrics are presented on a gross basis and include owned, rented and leased compressors at certain facilities.
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(2)
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Capacity excludes 170 MBbls/d of fractionation capacity attributable to the Mont Belvieu JV and 15 MBbls/d and 2 MBbls/d of stabilization capacity attributable to the Brasada and DBM complexes, respectively.
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(3)
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Includes 100% of Chipeta throughput, 50% of Newcastle and DBJV system throughput, 22% of Rendezvous throughput and 14.81% of Fort Union throughput, and throughput related to the Dew and Pinnacle systems (115 MMcf/d for the seven months ended July 31, 2015) prior to their divestiture in July 2015 (see
Acquisitions and Divestitures
within these Items 1 and 2).
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(4)
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Represents total throughput measured in barrels, consisting of throughput from our Chipeta NGL pipeline, our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput and our 33.33% share of average FRP throughput. See
Properties
below for further descriptions of these systems.
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(5)
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See
General Trends and Outlook
, under Part II, Item 7 of this Form 10-K regarding the incident that occurred at our DBM complex.
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•
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Pursuing accretive acquisitions.
We expect to continue to pursue accretive acquisitions of midstream energy assets from Anadarko and third parties.
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•
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Capitalizing on organic growth opportunities.
We expect to grow certain of our systems organically over time by meeting Anadarko’s and our other customers’ midstream service needs that result from their drilling activity in our areas of operation. We continually evaluate economically attractive organic expansion opportunities in existing or new areas of operation that allow us to leverage our existing infrastructure, operating expertise and customer relationships by constructing and expanding systems to meet new or increased demand of our services.
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Increasing third-party volumes to our systems.
We continue to actively market our midstream services to, and pursue strategic relationships with, third-party producers and customers with the intention of attracting additional volumes and/or expansion opportunities.
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Managing commodity price exposure.
We intend to continue limiting our direct exposure to commodity price changes and promote cash flow stability by pursuing a contract structure designed to mitigate exposure to a majority of the commodity price uncertainty through the use of fee-based contracts and fixed-price hedges.
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Maintaining investment grade metrics.
We intend to operate at appropriate leverage and distribution coverage levels in line with other partnerships in our sector that maintain investment grade credit ratings. By maintaining investment grade credit metrics, in part through staying within leverage ratios appropriate for investment-grade partnerships, we believe that we will be able to pursue strategic acquisitions and large growth projects at a lower cost of fixed-income capital, which would enhance their accretion and overall return.
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Affiliation with Anadarko.
We believe Anadarko is motivated to promote and support the successful execution of our business plan and to use its relationships throughout the energy industry, including those with producers and customers in the United States, to pursue projects that help to enhance the value of our business. See
Our Relationship with Anadarko Petroleum Corporation
below.
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Commodity price and volumetric risk mitigation.
Our cash flows are largely protected from fluctuations caused by commodity price volatility due to (i) the approximately 91% of our services that are provided pursuant to long-term, fee-based agreements and (ii) the commodity price swap agreements that limit our exposure to commodity price changes with respect to a majority of our percent-of-proceeds and keep-whole contracts. For the year ended
December 31, 2015
,
98%
of our gross margin was derived from either long-term, fee-based contracts or from percent-of-proceeds or keep-whole agreements that were hedged with commodity price swap agreements. On June 25, 2015, we extended our commodity price swap agreements with Anadarko for the DJ Basin complex from July 1, 2015, through December 31, 2015, and for the Hugoton system from October 1, 2015, through December 31, 2015. On December 8, 2015, the DJ Basin complex and Hugoton system swaps were further extended from January 1, 2016, through December 31, 2016. See
Risk Factors
under Part I, Item 1A and
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K. In addition, we mitigate volumetric risk by entering into contracts with cost of service or demand charge structures. For the year ended December 31, 2015, and excluding throughput measured in barrels, 44% of our throughput was subject to demand charges and 27% of our throughput was contracted under a cost of service model.
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Liquidity to pursue expansion and acquisition opportunities
.
We believe our operating cash flows, borrowing capacity, long-term relationships and reasonable access to debt and equity capital markets provide us with the liquidity to competitively pursue acquisition and expansion opportunities and to execute our strategy across capital market cycles. As of
December 31, 2015
, we had
$300 million
of outstanding borrowings and
$6.4 million
in outstanding letters of credit issued under our $1.2 billion RCF.
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Substantial presence in basins with historically strong producer economics.
Certain of our systems are in areas, such as the Delaware and DJ Basins, and the Eagleford shale, which have historically seen robust producer activity and are considered to have some of the most favorable producer returns for onshore North America. Our assets in these areas serve production where the hydrocarbons contain not only natural gas, but also oil, condensate and NGLs. In addition, our interests in the Anadarko-Operated and Non-Operated Marcellus gathering systems serve dry gas production from the Marcellus shale, which is considered to have some of the most abundant low-cost, dry gas reserves due to the overall scale and quality of the underlying resource. See
Properties
below for further asset descriptions.
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Well-positioned and well-maintained assets.
We believe that our asset portfolio, which is located in geographically diverse areas of operation, provides us with opportunities to expand and attract additional volumes to our systems from multiple productive reservoirs. Moreover, our portfolio includes an integrated package of high-quality, well-maintained assets for which we have implemented modern processing, treating, measurement and operating technologies.
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Consistent track record of accretive acquisitions.
Since our IPO in 2008, our management team has successfully executed ten related-party acquisitions and six third-party acquisitions, with an aggregate value of $5.1 billion (inclusive of the forecasted cash payment of
$282.8 million
for the acquisition of DBJV in March 2020, see
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K). Our management team has demonstrated its ability to identify, evaluate, negotiate, consummate and integrate strategic acquisitions and expansion projects, and it intends to use its experience and reputation to continue to grow the Partnership through accretive acquisitions, focusing on opportunities to improve throughput volumes and cash flows.
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Gathering.
At the initial stages of the midstream value chain, a network of typically smaller diameter pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow gathering of additional production without significant incremental capital expenditures.
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Stabilization.
In connection with our gathering services, we sometimes retain, stabilize and sell drip condensate, which falls out of the natural gas stream during gathering. Stabilization is a process that separates the heavier hydrocarbons (which also serve as valuable commodities) found in natural gas, typically referred to as “liquids-rich” natural gas, from the lighter components by using a distillation process or by reducing the pressure and letting the more volatile components flash. We provide stabilization for condensate at many of our processing plants (such as the DJ Basin, Brasada and DBM complexes).
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Compression.
Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which allows the natural gas to be gathered more efficiently and delivered into a higher pressure system, processing plant or pipeline. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Since wells produce at progressively lower field pressures as they deplete, field compression is needed to maintain throughput across the gathering system.
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Treating and dehydration.
To the extent that gathered natural gas contains water vapor or contaminants, such as carbon dioxide and hydrogen sulfide, it is dehydrated to remove the saturated water and treated to separate the carbon dioxide and hydrogen sulfide from the gas stream.
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Processing.
Processing separates the heavier and more valuable hydrocarbon components, which are extracted as NGLs, from the remaining residue. The remaining residue is then designated for long-haul pipeline transportation or commercial use.
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Fractionation.
Fractionation is the process of applying various levels of higher pressure and lower temperature to separate a stream of NGLs into ethane, propane, normal butane, isobutane and natural gasoline for end-use sale.
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Storage, transportation and marketing.
Once the raw natural gas has been treated or processed and the raw NGL mix has been fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located both throughout the pipeline network and at major market centers to better accommodate seasonal demand and daily supply-demand shifts. We do not currently offer storage services.
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Fee-based.
Under fee-based arrangements, the service provider typically receives a fee for each unit of natural gas gathered, treated and/or processed at its facilities. As a result, the price per unit received by the service provider does not vary with commodity price changes, minimizing the service provider’s direct commodity price risk exposure.
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Percent-of-proceeds, percent-of-value or percent-of-liquids.
Percent-of-proceeds, percent-of-value or percent-of-liquids arrangements may be used for gathering and processing services. Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue and/or NGLs or a percentage of the actual residue and/or NGLs at the tailgate. These types of arrangements expose the processor to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price of natural gas and/or NGLs.
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Keep-whole.
Keep-whole arrangements may be used for processing services. Under these arrangements, the service provider keeps 100% of the NGLs produced, and the processed natural gas, or value of the gas, is returned to the producer. Since some of the gas is used and removed during processing, the processor compensates the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas utilized. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.
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Firm.
Firm service requires the reservation of capacity by a customer between certain receipt and delivery points or within a processing facility. Firm customers generally pay a demand or capacity reservation fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus, in specific cases, a usage fee based on the volumes gathered, processed or transported.
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Interruptible.
Interruptible service is typically short-term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume actually gathered, processed or transported. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and, as such, customers receiving services under interruptible contracts are not assured capacity.
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Location
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Asset
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Type
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Processing / Treating Plants
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Processing / Treating Capacity (MMcf/d)
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Compressors
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Compression Horsepower
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Gathering Systems
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Pipeline Miles
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Northeast Wyoming
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Bison
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Treating
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3
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450
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8
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14,320
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—
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—
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Northeast Wyoming
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Fort Union
(1)
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Gathering & Treating
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3
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295
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3
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5,454
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1
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318
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Northeast Wyoming
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Hilight
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Gathering & Processing
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2
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60
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43
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46,919
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1
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1,315
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Northeast Wyoming
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Newcastle
(1)
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Gathering & Processing
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1
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3
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6
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2,660
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1
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180
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Southwest Wyoming
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Granger complex
(2)
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Gathering & Processing
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4
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500
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44
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48,617
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1
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834
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Southwest Wyoming
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Red Desert complex
(3)
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Gathering & Processing
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1
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125
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33
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58,129
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1
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1,033
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Southwest Wyoming
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Rendezvous
(4)
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Gathering
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—
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—
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5
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7,485
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1
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338
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Total
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14
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1,433
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142
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183,584
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6
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4,018
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(1)
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We have a 14.81% interest in Fort Union and a 50% interest in Newcastle.
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(2)
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The Granger complex includes the “Granger straddle plant,” a refrigeration processing plant.
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(3)
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The Red Desert complex includes the Red Desert cryogenic processing plant, which is currently inactive, and the Patrick Draw cryogenic processing plant.
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(4)
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We have a 22% interest in the Rendezvous gathering system, which is operated by a third party.
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•
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Customers.
Anadarko provided 52% of the throughput at the Bison treating facility for the year ended
December 31, 2015
. The remaining throughput was from two third-party producers.
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•
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Supply and delivery points
. The Bison treating facility treats and compresses gas from coal-bed methane wells in the Powder River Basin of Wyoming. The Bison pipeline, operated by TransCanada Corporation, is connected directly to the facility, which is currently the only inlet into the pipeline. The Bison treating facility is also directly connected to Fort Union’s pipeline.
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Customers.
Moriah Powder River LLC (“Moriah”), Copano Pipelines/Rocky Mountains, LLC
, Crestone Powder River LLC and Powder River Midstream, LLC hold a
majority of the firm capacity on the Fort Union system. Effective November 1, 2015, Anadarko released its contracted capacity to Moriah. To the extent capacity on the system is not used by these customers, it is available to third parties under interruptible agreements. During the year ended December 31, 2015, an impairment loss was recognized by the managing partner of Fort Union. See
Note 9—Equity Investments
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K.
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Supply.
Substantially all of Fort Union’s gas supply is comprised of coal-bed methane volumes that are either produced or gathered by the customers noted above throughout the Powder River Basin. Before September 1, 2015, the Fort Union system received gas from 1,900 Anadarko-operated coal-bed methane wells producing in the Big George coal play and a nearby multi-seam coal fairway. On September 1, 2015, Anadarko divested its interest in the Powder River Basin coal-bed methane to Moriah.
The
Fort Union customers noted above gather gas for delivery to Fort Union under contracts with acreage dedications from multiple producers in the heart of the basin and from the coal-bed methane producing area near Sheridan, Wyoming.
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Delivery points.
The Fort Union system delivers coal-bed methane gas to the hub in Glenrock, Wyoming, which has access to the following interstate pipelines:
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Colorado Interstate Gas Company LLC’s pipeline (“CIG”);
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Tallgrass Interstate Gas Transmission system’s pipeline (“TIGT”); and
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Wyoming Interstate Company’s pipeline (“WIC”).
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Customers.
Gas gathered and processed through the Hilight system is primarily from numerous third-party customers, with the six largest producers providing 75% of the system throughput during the year ended
December 31, 2015
. During the year ended December 31, 2015, the Hilight system was impaired to its estimated fair value. See
Note 7—Property, Plant and Equipment
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K.
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Supply.
The Hilight gathering system serves the gas gathering needs of several conventional producing fields in Johnson, Campbell, Natrona and Converse Counties, Wyoming.
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Delivery points.
The Hilight plant delivers residue into our MIGC transmission line (see
Transportation
within these Items
1 and 2). Hilight is not connected to an active NGL pipeline, resulting in all fractionated NGLs being sold locally through its truck and rail loading facilities.
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Customers.
Gas gathered and processed through the Newcastle system is from 11 third-party customers, with the largest three producers providing 84% of the system throughput during the year ended
December 31, 2015
. The largest producer provided 49% of the throughput during the year ended
December 31, 2015
.
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Supply.
The Newcastle gathering system and plant primarily service gas production from the Clareton and Finn-Shurley fields in Weston County, Wyoming. Due to infill drilling and enhanced production techniques, producers have continued to maintain production levels.
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Delivery points.
Propane products from the Newcastle plant are typically sold locally by truck, and the butane/gasoline mix products are transported to the Hilight plant for further fractionation. Residue from the Newcastle system is delivered into Black Hills Corporation’s MGTC, Inc. (“MGTC”) intrastate pipeline, a Hinshaw pipeline that supplies local markets in Wyoming, for transport, distribution and sale.
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Customers.
For the year ended
December 31, 2015
, 3% of the Granger complex throughput was from Anadarko and the remaining throughput was from various third-party customers, with the five largest shippers providing 86% of the system throughput.
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•
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Supply.
The Granger complex is supplied by the Moxa Arch and the Jonah and Pinedale Anticline fields. The Granger gas gathering system had 654 active receipt points as of
December 31, 2015
.
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•
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Delivery points.
The residue from the Granger complex can be delivered to the following major pipelines:
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◦
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CIG;
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◦
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Berkshire Hathaway Energy’s Kern River pipeline (“Kern River pipeline”) via a connect with Tesoro Logistics LP’s (“Tesoro”) Rendezvous pipeline (“Rendezvous pipeline”);
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◦
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Questar Pipeline Company (“Questar pipeline”);
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◦
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Questar Overthrust Pipeline (“Overthrust”);
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◦
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The Williams Companies, Inc.’s Northwest Pipeline (“NWPL”);
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◦
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our OTTCO pipeline; and
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◦
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our Mountain Gas Transportation LLC (“MGTI”).
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•
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Customers.
For the year ended
December 31, 2015
, 4% of the Red Desert complex throughput was from Anadarko and the remaining throughput was from various third-party customers, with the six largest producers providing 66% of the system throughput. During the year ended December 31, 2015, the Red Desert complex was impaired to its estimated salvage value. See
Note 7—Property, Plant and Equipment
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K.
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•
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Supply.
The Red Desert complex gathers, compresses, treats and processes natural gas and fractionates NGLs produced in the eastern portion of the Greater Green River Basin, providing service primarily to the Red Desert and Washakie Basins.
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•
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Delivery points.
Residue from the Red Desert complex is delivered to CIG and WIC, while NGLs are delivered to MAPL, as well as to truck and rail loading facilities.
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•
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Customers.
Tesoro and Anadarko are the only firm shippers on the Rendezvous gathering system. To the extent capacity on the system is not used by those shippers, it is available to third parties under interruptible agreements.
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•
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Supply and delivery points.
The Rendezvous gathering system provides high pressure gathering service for gas from the Jonah and Pinedale Anticline fields and delivers to our Granger plant, as well as Tesoro’s Blacks Fork gas processing plant, which connects to the Questar pipeline, NWPL and the Kern River pipeline via the Rendezvous pipeline.
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Location
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Asset
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Type
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Processing / Treating Plants
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Processing / Treating Capacity (MMcf/d)
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Compressors
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Compression Horsepower
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Gathering Systems
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Pipeline Miles
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||||||
Colorado
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DJ Basin complex
(1)
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Gathering, Processing & Treating
|
|
9
|
|
|
919
|
|
|
117
|
|
|
262,564
|
|
|
2
|
|
|
3,137
|
|
Utah
|
|
Chipeta
(2)
|
|
Processing
|
|
4
|
|
|
980
|
|
|
18
|
|
|
84,007
|
|
|
—
|
|
|
—
|
|
Utah
|
|
Clawson
|
|
Gathering & Treating
|
|
2
|
|
|
20
(3)
|
|
|
5
|
|
|
6,310
|
|
|
1
|
|
|
31
|
|
Utah
|
|
Helper
|
|
Gathering & Treating
|
|
3
|
|
|
32
(3)
|
|
|
11
|
|
|
14,075
|
|
|
1
|
|
|
85
|
|
Total
|
|
|
|
|
|
18
|
|
|
1,951
|
|
|
151
|
|
|
366,956
|
|
|
4
|
|
|
3,253
|
|
(1)
|
The DJ Basin complex includes the Platte Valley, Fort Lupton, Fort Lupton JT, Hambert JT, and Lancaster Trains I and II processing plants, the Platteville amine treating plant, and the Wattenberg gathering system.
|
(2)
|
We are the managing member of and own a 75% interest in Chipeta. Chipeta owns the Chipeta processing complex and the Natural Buttes refrigeration plant.
|
(3)
|
At current carbon dioxide
levels and operating conditions.
|
•
|
Customers.
For the year ended
December 31, 2015
, 67% of the DJ Basin complex throughput was from Anadarko and the remaining throughput was from various third-party customers, with the largest providing 20% of the throughput.
|
•
|
Supply and delivery points.
There were 2,753 active receipt points connected to the DJ Basin complex as of
December 31, 2015
. The DJ Basin complex is primarily supplied by the Wattenberg field, in which Anadarko controls 866,000 gross acres and drilled 365 wells and completed 276 wells during the year ended
December 31, 2015
.
|
◦
|
Anadarko’s Wattenberg plant;
|
◦
|
DCP Midstream LP’s (“DCP”) Spindle, Mewbourn and Platteville plants; and
|
◦
|
AKA Energy Group, LLC’s Gilcrest plant.
|
•
|
Customers.
Anadarko is the largest customer on the Chipeta system with 77% of the system throughput for the year ended
December 31, 2015
. The balance of throughput on the system during the year ended
December 31, 2015
was from 14
third-party customers.
|
•
|
Supply.
The Chipeta system is well positioned to access Anadarko and third-party production in the Uinta Basin where Anadarko controls 249,000 gross acres. Chipeta’s inlet is connected to Anadarko’s Natural Buttes gathering system, the Questar pipeline and the Three Rivers Gathering, LLC’s system, which is owned by Ute Energy and another third party.
|
•
|
Delivery points.
The Chipeta plant delivers NGLs to MAPL, which provides transportation through Enterprise’s Seminole pipeline (“Seminole pipeline”) and TEP’s pipeline in West Texas and ultimately to the NGL fractionation and storage facilities in Mont Belvieu, Texas. The Chipeta plant has natural gas delivery points through the following pipelines delivering to markets throughout the Rockies and Western United States:
|
◦
|
CIG;
|
◦
|
Questar pipeline; and
|
◦
|
WIC.
|
•
|
Customers.
Anadarko is the only shipper on the Clawson gathering system.
|
•
|
Supply.
The Clawson Springs field covers 7,600 gross acres and produces primarily from the Ferron Coal play.
|
•
|
Delivery points.
The Clawson gathering system delivers into the Questar pipeline. The Questar pipeline provides transportation to regional markets in Wyoming, Colorado and Utah and also delivers into the Kern River pipeline, which provides transportation to markets in the Western United States, primarily California.
|
•
|
Customers.
Anadarko is the only shipper on the Helper gathering system.
|
•
|
Supply.
The Helper and the Cardinal Draw fields are Anadarko-operated coal-bed methane developments on the southwestern edge of the Uinta Basin that produce from the Ferron Coal play. Anadarko owns 19,000 gross acres in the Helper field and 20,000 gross acres in the Cardinal Draw field.
|
•
|
Delivery points.
The Helper gathering system delivers into the Questar pipeline. The Questar pipeline provides transportation to regional markets in Wyoming, Colorado and Utah and also delivers into the Kern River pipeline, which provides transportation to markets in the Western United States, primarily California.
|
Location
|
|
Asset
|
|
Type
|
|
Compressors
|
|
Compression Horsepower
|
|
Gathering Systems
|
|
Pipeline Miles
|
||||
Southwest Kansas & Oklahoma
|
|
Hugoton
|
|
Gathering
|
|
87
|
|
|
90,214
|
|
|
1
|
|
|
2,097
|
|
North-central Pennsylvania
|
|
Non-Operated Marcellus
(1)
|
|
Gathering
|
|
25
|
|
|
70,000
|
|
|
2
|
|
|
521
|
|
North-central Pennsylvania
|
|
Anadarko-Operated Marcellus
(2)
|
|
Gathering
|
|
5
|
|
|
6,900
|
|
|
3
|
|
|
151
|
|
Total
|
|
|
|
|
|
117
|
|
|
167,114
|
|
|
6
|
|
|
2,769
|
|
(1)
|
We own a 33.75% interest in the Non-Operated Marcellus Interest gathering systems, with a third party serving as the operator.
|
(2)
|
We own a 33.75% interest in the Anadarko-Operated Marcellus Interest gathering systems, with Anadarko serving as the operator.
|
•
|
Customers.
Anadarko is the largest customer on the Hugoton gathering system with 88% of the system throughput during the year ended
December 31, 2015
. Two third-party shippers account for 7% of the system throughput, with the balance from various other third-party shippers.
|
•
|
Supply.
The Hugoton field continues to be a long-life, low-decline asset for Anadarko, which has an extensive acreage position in the field with 470,000 gross acres. A 200-barrel-per-day condensate stabilization facility is currently under construction and will be operational in the first quarter of 2016.
|
•
|
Delivery points.
The Hugoton gathering system is connected to the Satanta plant, which is owned by Anadarko (49%) and a third party. The Satanta plant processes NGLs and helium, and delivers residue into the Kansas Gas Service’s pipeline and Southern Star Central Gas Pipeline, Inc.’s pipeline. The system is also connected to DCP’s National Helium Plant, which extracts NGLs and delivers residue into Energy Transfer Partners, LP’s (“ETP”) Panhandle Eastern Pipe Line.
|
•
|
Customers.
As of
December 31, 2015
, in addition to Anadarko, the Non-Operated Marcellus Interest gathering systems had seven priority shippers on its Rome gathering system and six priority shippers on its Liberty gathering system. Also as of December 31, 2015, in addition to Anadarko, the Anadarko-Operated Marcellus Interest gathering systems had six priority shippers. For the year ended
December 31, 2015
, Anadarko represented 18% and 40% of throughput on the Non-Operated Marcellus Interest gathering systems and the Anadarko-Operated Marcellus Interest gathering systems, respectively. Capacity not used by priority shippers is available to third parties.
|
•
|
Supply and delivery points.
As of
December 31, 2015
, Anadarko had a working interest in over 625,000 gross acres within the Marcellus shale. The Non-Operated Marcellus Interest gathering systems have access to Transcontinental Gas Pipeline Company, LLC’s pipeline (“TRANSCO”), Tennessee Gas Pipeline Company, LLC’s pipeline and Millennium Pipeline Company, LLC’s pipeline. The Anadarko-Operated Marcellus Interest gathering systems have access to TRANSCO.
|
Location
|
|
Asset
|
|
Type
|
|
Processing / Treating Plants
|
|
Processing / Treating Capacity (MMcf/d)
|
|
Processing Capacity (MBbls/d)
|
|
Compressors
(1)
|
|
Compression Horsepower
(1)
|
|
Gathering Systems
|
|
Pipeline Miles
|
|||||||
East Texas
|
|
Mont Belvieu JV
(2)
|
|
Processing
|
|
2
|
|
|
—
|
|
|
170
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
South Texas
|
|
Brasada complex
(3)
|
|
Gathering, Processing & Treating
|
|
3
|
|
|
200
|
|
|
15
|
|
|
14
|
|
|
30,450
|
|
|
1
|
|
|
57
|
|
West Texas
|
|
Haley
|
|
Gathering
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
15,100
|
|
|
1
|
|
|
155
|
|
West Texas
|
|
DBM complex
(4)
|
|
Gathering, Processing & Treating
|
|
3
|
|
|
300
|
|
|
2
|
|
|
53
|
|
|
82,010
|
|
|
1
|
|
|
321
|
|
West Texas
|
|
DBJV system
(5)
|
|
Gathering & Treating
|
|
4
|
|
|
320
|
|
|
—
|
|
|
42
|
|
|
54,405
|
|
|
1
|
|
|
456
|
|
Total
|
|
|
|
|
|
12
|
|
|
820
|
|
|
187
|
|
|
119
|
|
|
181,965
|
|
|
4
|
|
|
989
|
|
(1)
|
Includes owned, rented and leased compressors and compression horsepower.
|
(2)
|
We own a 25% interest in the Mont Belvieu JV, which owns two NGL fractionation trains. A third party serves as the operator.
|
(3)
|
Includes 15 MBbls/d of condensate stabilization capacity at the Brasada complex.
|
(4)
|
Excludes 1,775 gpm of amine treating capacity at the DBM complex. Trains IV and V are currently under construction. See
Assets Under Development
below and
General Trends and Outlook
, under Part II, Item 7 of this Form 10-K.
|
(5)
|
We own a 50% interest in the DBJV system and serve as the operator.
|
•
|
Customers.
The Mont Belvieu JV does not directly contract with customers, but rather is allocated volumes from Enterprise based on the available capacity of the other trains at Enterprise’s NGL fractionation complex in Mont Belvieu, Texas.
|
•
|
Supply and delivery points.
Enterprise receives volumes at its fractionation complex in Mont Belvieu, Texas via a large number of pipelines that terminate there, including the Seminole pipeline, Skelly-Belvieu Pipeline Company, LLC’s pipeline and TEP. Individual NGLs are delivered to end users either through customer-owned pipelines that are connected to nearby petrochemical plants or via export terminal.
|
•
|
Customers.
Anadarko provides 100% of the throughput to the Brasada complex. Anadarko delivers gas and condensate to the plant on behalf of itself and its upstream joint interest owners.
|
•
|
Supply.
Supply of gas and NGLs for the facility comes from Anadarko’s production in the Eagleford shale, in which Anadarko controls 346,000 gross acres.
|
•
|
Delivery points.
The facility delivers residue gas into the Eagle Ford Midstream system operated by NET Midstream, LLC. It delivers stabilized condensate into Plains All American Pipeline and NGLs into the South Texas NGL Pipeline System operated by Enterprise.
|
•
|
Customers.
Anadarko’s production represented 77% of the Haley gathering system’s throughput for the year ended
December 31, 2015
. The remaining throughput was attributable to one third-party producer.
|
•
|
Supply.
As of
December 31, 2015
, Anadarko holds an interest in over 600,000 gross acres in the greater Delaware Basin, a portion of which is gathered by the Haley gathering system.
|
•
|
Delivery points.
The Haley gathering system provides both lean and rich gas gathering service. The lean service delivery point is into Enterprise GC, LLC’s pipeline for ultimate delivery into ETP’s Oasis pipeline (the “Oasis pipeline”). The rich service system delivery point is into a high pressure gathering line (the “Avalon Express pipeline”), which is part of our DBJV system. The Avalon Express pipeline can deliver gas into either the Bone Spring Gas Processing plant (the “Bone Spring plant”) or the Mi Vida Gas Processing plant (the “Mi Vida plant”) for NGL extraction, both of which are partially owned by Anadarko. Downstream pipelines at the plant tailgates include the Oasis and Transwestern pipelines at the Bone Spring plant and the Oasis pipeline at the Mi Vida plant. These downstream pipelines provide transportation to both the Waha Hub and Houston Ship Channel markets.
|
•
|
Customers.
Gas gathered and processed through the DBM complex is primarily from third-party producers, with the three largest producers providing 62% of the system throughput for the year ended
December 31, 2015
.
|
•
|
Supply.
Supply of gas and NGLs for the complex comes from production from the Delaware Sands, Avalon Shale, Bone Spring and Wolfcamp formations in the Delaware Basin portion of the Permian Basin. Anadarko holds an interest in over 600,000 gross acres within the Delaware Basin.
|
•
|
Delivery points.
Residue gas produced at the facility is delivered to an interconnect with the El Paso Natural Gas pipeline. NGL production is delivered into both the Sand Hills pipeline and the Lone Star NGL LLC’s pipeline.
|
•
|
Customers.
Anadarko’s production represented 74% of the DBJV system’s throughput for the year ended
December 31, 2015
. The remaining throughput was attributable to one third-party producer.
|
•
|
Supply.
The system gathers lean Penn gas, as well as liquids-rich Bone Spring, Avalon and Wolfcamp gas.
|
•
|
Delivery points.
Rich Avalon, Bone Spring and Wolfcamp gas is dehydrated, compressed and delivered to both the Bone Spring plant and the Mi Vida plant for processing, while Lean Penn gas is delivered into Enterprise GC, LP. Residue gas from the Bone Spring and Mi Vida plants is delivered into the Oasis pipeline or Transwestern pipeline.
|
Location
|
|
Asset
|
|
Type
|
|
Compressors /
Pump Stations
|
|
Operational Horsepower
|
|
Pipeline Miles
|
|||
Northeast Wyoming
|
|
MIGC
(1)
|
|
Gas
|
|
15
|
|
|
23,794
|
|
|
246
|
|
Southwest Wyoming
|
|
OTTCO
|
|
Gas
|
|
1
|
|
|
3,174
|
|
|
217
|
|
Utah
|
|
GNB NGL
(1)
|
|
NGL
|
|
—
|
|
|
—
|
|
|
32
|
|
Colorado, Kansas, Oklahoma
|
|
White Cliffs
(1) (2)
|
|
Oil
|
|
12
|
|
|
15,000
|
|
|
1,054
|
|
Colorado, Oklahoma, Texas
|
|
FRP
(1) (3)
|
|
NGL
|
|
6
|
|
|
12,000
|
|
|
435
|
|
Texas, Oklahoma
|
|
TEG
(3)
|
|
NGL
|
|
19
|
|
|
1,895
|
|
|
117
|
|
Texas
|
|
TEP
(1) (3)
|
|
NGL
|
|
12
|
|
|
27,000
|
|
|
593
|
|
Texas
|
|
Ramsey Residue Line
(1)
|
|
Gas
|
|
—
|
|
|
—
|
|
|
9
|
|
Total
|
|
|
|
|
|
65
|
|
|
82,863
|
|
|
2,703
|
|
(1)
|
MIGC, GNB NGL, White Cliffs, FRP, TEP and the Ramsey Residue Line (at the DBM complex) are regulated by FERC.
|
(2)
|
We own a 10% interest in the White Cliffs pipeline, which is operated by a third party.
|
(3)
|
We own a 20% interest in TEG and TEP and a 33.33% interest in FRP. All three systems are operated by third parties.
|
•
|
Customers.
Anadarko is the largest firm shipper on the MIGC system, with 90% of the throughput for the year ended
December 31, 2015
. The remaining throughput on the MIGC system was from 18 third-party shippers. MIGC is certificated for 175 MMcf/d of firm transportation capacity.
|
•
|
Supply.
MIGC receives gas from various coal-bed methane gathering systems in the Powder River Basin and the Hilight system, as well as from WBI Energy Transmission, Inc. on the north end of the transportation system.
|
•
|
Delivery points.
MIGC volumes can be redelivered to the hub in Glenrock, Wyoming, which has access to the following interstate pipelines:
|
◦
|
CIG;
|
◦
|
TIGT; and
|
◦
|
WIC.
|
•
|
Customers.
For the year ended
December 31, 2015
, 12% of OTTCO’s throughput was from Anadarko. The remaining throughput on the OTTCO transportation system was from two third-party shippers. Revenues on the OTTCO transportation system are generated from contract demand charges and volumetric fees paid by shippers under firm and interruptible gas transportation agreements.
|
•
|
Supply and delivery points.
Supply points to the OTTCO transportation system include approximately 50 wellheads, the Granger complex and ExxonMobil Corporation’s Shute Creek plant, which are supplied by the eastern portion of the Greater Green River Basin, the Moxa Arch and the Jonah and Pinedale Anticline fields. Primary delivery points include the Red Desert complex, two third-party industrial facilities and an inactive interconnection with the Kern River pipeline.
|
•
|
Customers.
Anadarko was the only shipper on the GNB NGL pipeline for the year ended
December 31, 2015
.
|
•
|
Supply.
The GNB NGL pipeline receives NGLs from Chipeta’s gas processing facility and Tesoro’s Stagecoach/Iron Horse gas processing complex.
|
•
|
Delivery points.
The GNB NGL pipeline delivers NGLs to MAPL, which provides transportation through the Seminole pipeline and TEP in West Texas, and ultimately to NGL fractionation and storage facilities in Mont Belvieu, Texas.
|
•
|
Customers.
The White Cliffs pipeline had multiple committed shippers, including Anadarko, during the year ended
December 31, 2015
. In addition, other parties may ship on the White Cliffs pipeline at FERC-based rates. The White Cliffs dual pipeline system provides 150 MBbls/d of crude takeaway capacity from Platteville, Colorado to Cushing, Oklahoma. White Cliffs is currently undergoing an expansion project that will increase the pipeline’s capacity to approximately 215 MBbls/d. This expansion project is scheduled to be completed in the first half of 2016.
|
•
|
Supply.
The White Cliffs pipeline is supplied by production from the DJ Basin and offers the only direct route from the DJ Basin to Cushing, Oklahoma.
|
•
|
Delivery points.
The White Cliffs pipeline delivery point is SemCrude’s storage facility in Cushing, Oklahoma, a major crude oil marketing center, which ultimately delivers to Gulf Coast and mid-continent refineries. At the point of origin, it has a 330,000-barrel storage facility adjacent to a truck-unloading facility.
|
•
|
Front Range Pipeline.
FRP provides takeaway capacity from the DJ Basin in Northeast Colorado. FRP has injection points from gas plants in Weld County, Colorado (including our Lancaster plant), which is within the DJ Basin complex (see
Rocky Mountains—Colorado and Utah
within these Items 1 and 2). FRP connects to TEP near Skellytown, Texas. During the year ended
December 31, 2015
, FRP had two committed shippers, including Anadarko, and provides capacity for other shippers at the posted FERC tariff rate.
|
•
|
Texas Express Gathering.
TEG consists of two NGL gathering systems that provide plants in North Texas, the Texas panhandle and West Oklahoma with access to NGL takeaway capacity on TEP. TEG had one committed shipper during the year ended
December 31, 2015
.
|
•
|
Texas Express Pipeline.
TEP delivers to NGL fractionation and storage facilities in Mont Belvieu, Texas. At Skellytown, Texas, TEP is supplied with NGLs from other pipelines including FRP and MAPL. TEP had multiple committed shippers, including Anadarko, during the year ended
December 31, 2015
and provides capacity for other shippers at the posted FERC tariff rates.
|
•
|
DBM Trains IV, V and VI:
We are currently constructing Trains IV and V at our DBM complex with 200 MMcf/d of designed processing capacity per train and in-service dates expected during the first half (Train IV) and second half (Train V) of 2016. We have also made progress payments towards the construction of another cryogenic unit at our DBM complex (Train VI), with an expected in-service date of mid-2017.
|
•
|
Ramsey Residue Line Expansion:
We began construction of a new residue gas pipeline that will extend from the tailgate of the DBM complex to Kinder Morgan’s El Paso Natural Gas Pipeline system located approximately 9 miles north of the complex. It is anticipated the new line will be in service during the first half of 2016.
|
System
|
|
Competitor(s)
|
|
|
|
Anadarko-Operated Marcellus Interest gathering systems
|
|
ETP and National Fuel Gas Midstream Corporation
|
Bison treating facility
|
|
Thunder Creek Gas Services, LLC and Fort Union (treating only)
|
Brasada gathering system, stabilization facility and processing complex
|
|
Enterprise, ETP, Targa Resources, LP, Kinder Morgan, Inc., Plains All American Pipeline and Howard Energy Partners
|
Chipeta processing complex
|
|
Tesoro and Kinder Morgan, Inc.
|
DBJV system
|
|
ETP, Outrigger Midstream, Enterprise GC, LP, Targa Resources, LP
|
DBM gathering system, treating facility and processing complex
|
|
ETP, Enterprise GC, LP, Enlink Midstream, LP, MPLX LP, and Targa Midstream, LP
|
DJ Basin gathering system, treating facility and processing complex
|
|
DCP and AKA Energy Group, LLC
|
Fort Union gathering system and treating facility
|
|
Bison treating facility (carbon dioxide treating services only), MIGC, Thunder Creek Gas Services, LLC and TransCanada Corporation
|
Granger gathering system and processing complex
|
|
Williams Field Services, Enterprise/Jonah Gas Gathering Company and Tesoro
|
Haley gathering system
|
|
ETP, Outrigger Midstream, Enterprise GC, LP and Targa Midstream Services, LP
|
Helper and Clawson gathering systems and treating facilities
|
|
XTO Energy
|
Hilight gathering system and processing plant
|
|
DCP, ONEOK Gas Gathering Company, Thunder Creek Gas Services, LLC, Crestwood-Access, Tallgrass Energy Partners, LP and Agave Energy Company
|
Hugoton gathering system
|
|
ONEOK Gas Gathering Company, DCP and Linn Energy
|
Mont Belvieu JV fractionation trains
|
|
Targa Resources LP, Phillips 66, Lone Star NGL LLC and ONEOK Partners, LP
|
Newcastle gathering system and processing plant
|
|
DCP
|
Non-Operated Marcellus Interest gathering systems
|
|
ETP
|
Red Desert gathering system and processing complex
|
|
Williams Field Services and Tesoro
|
Rendezvous gathering system
|
|
No significant direct competition
|
•
|
rates, services, and terms and conditions of service;
|
•
|
types of services that may be offered to customers;
|
•
|
certification and construction of new facilities;
|
•
|
acquisition, extension, disposition or abandonment of facilities;
|
•
|
maintenance of accounts and records;
|
•
|
internet posting requirements for available capacity, discounts and other matters;
|
•
|
pipeline segmentation to allow multiple simultaneous shipments under the same contract;
|
•
|
capacity release to create a secondary market for transportation services;
|
•
|
relationships between affiliated companies involved in certain aspects of the natural gas business;
|
•
|
initiation and discontinuation of services;
|
•
|
market manipulation in connection with interstate sales, purchases or transportation of natural gas and NGLs; and
|
•
|
participation by interstate pipelines in cash management arrangements.
|
•
|
the U.S. Clean Air Act, which restricts the emission of air pollutants from many sources, imposes various pre-construction, monitoring, and reporting requirements, and the EPA uses as its basis for adopting greenhouse gas regulatory initiatives.
|
•
|
the U.S. Federal Water Pollution Control Act, also known as the Federal Clean Water Act, which regulates discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemakings as protected waters of the United States.
|
•
|
the U.S. Oil Pollution Act of 1990, which subjects owners and operators of onshore facilities and pipelines to liability for removal costs and damages arising from an oil spill in waters of the United States.
|
•
|
the Comprehensive Environmental Response, Compensation and Liability Act of 1980, which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur.
|
•
|
the U.S. Resource Conservation and Recovery Act, which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes.
|
•
|
the U.S. Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources.
|
•
|
the U.S. Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories.
|
•
|
the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas.
|
•
|
the National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment.
|
•
|
our ability to pay distributions to our unitholders;
|
•
|
our and Anadarko’s assumptions about the energy market;
|
•
|
future throughput, including Anadarko’s production, which is gathered or processed by or transported through our assets, and any corresponding commodity price swap agreements with Anadarko;
|
•
|
our operating results;
|
•
|
competitive conditions;
|
•
|
technology;
|
•
|
the availability of capital resources to fund acquisitions, capital expenditures and other contractual obligations, and our ability to access those resources from Anadarko or through the debt or equity capital markets;
|
•
|
the supply of, demand for, and the price of, oil, natural gas, NGLs and related products or services;
|
•
|
weather and natural disasters;
|
•
|
inflation;
|
•
|
the availability of goods and services;
|
•
|
general economic conditions, either internationally or domestically or in the jurisdictions in which we are doing business;
|
•
|
federal, state and local laws, including those that limit Anadarko and other producers’ hydraulic fracturing or other oil and natural gas operations;
|
•
|
environmental liabilities;
|
•
|
legislative or regulatory changes, including changes affecting our status as a partnership for federal income tax purposes;
|
•
|
changes in the financial or operational condition of Anadarko;
|
•
|
the creditworthiness of Anadarko or our other counterparties, including financial institutions, operating partners, and other parties;
|
•
|
changes in Anadarko’s capital program, strategy or desired areas of focus;
|
•
|
our commitments to capital projects;
|
•
|
our ability to use our RCF;
|
•
|
our ability to repay debt;
|
•
|
our ability to mitigate exposure to the commodity price risks inherent in our percent-of-proceeds and keep-whole contracts;
|
•
|
conflicts of interest among us, our general partner, WGP and its general partner, and affiliates, including Anadarko;
|
•
|
our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;
|
•
|
our ability to acquire assets on acceptable terms;
|
•
|
non-payment or non-performance of Anadarko or other significant customers, including under our gathering, processing and transportation agreements and our $260.0 million note receivable from Anadarko;
|
•
|
the timing, amount and terms of future issuances of equity and debt securities; and
|
•
|
other factors discussed below and elsewhere in this Item 1A, under the caption
Critical Accounting Policies and Estimates
included under Part II, Item 7 of this Form 10-K, and in our other public filings and press releases.
|
•
|
the volatility of oil and natural gas prices, which could have a negative effect on the value of Anadarko’s oil and natural gas properties, its drilling programs or its ability to finance its operations;
|
•
|
the availability of capital on an economic basis to fund Anadarko’s exploration and development activities;
|
•
|
a reduction in or reallocation of Anadarko’s capital budget, which could reduce the gathering, transportation and treating volumes available to us as a midstream operator, limit our midstream opportunities for organic growth or limit the inventory of midstream assets we may acquire from Anadarko;
|
•
|
Anadarko’s ability to replace its oil and natural gas reserves;
|
•
|
Anadarko’s operations in foreign countries, which are subject to political, economic and other uncertainties;
|
•
|
Anadarko’s drilling and operating risks, including potential environmental liabilities;
|
•
|
transportation capacity constraints and interruptions;
|
•
|
adverse effects of governmental and environmental regulation; and
|
•
|
adverse effects from current or future litigation.
|
•
|
domestic and worldwide economic and geopolitical conditions;
|
•
|
weather conditions and seasonal trends;
|
•
|
the ability to develop recently discovered fields or deploy new technologies to existing fields;
|
•
|
the levels of domestic production and consumer demand, as affected by, among other things, concerns over inflation, geopolitical issues and the availability and cost of credit;
|
•
|
the availability of imported or a market for exported liquefied natural gas;
|
•
|
the availability of transportation systems with adequate capacity;
|
•
|
the volatility and uncertainty of regional pricing differentials, such as in the Mid-Continent or Rocky Mountains;
|
•
|
the price and availability of alternative fuels;
|
•
|
the effect of energy conservation measures;
|
•
|
the nature and extent of governmental regulation and taxation; and
|
•
|
the forecasted supply and demand for, and prices of, oil, natural gas, NGLs and other commodities.
|
•
|
the prices of, level of production of, and demand for natural gas;
|
•
|
the volume of natural gas we gather, compress, process, treat and transport;
|
•
|
the volumes and prices of NGLs and condensate that we retain and sell;
|
•
|
demand charges and volumetric fees associated with our transportation services;
|
•
|
the level of competition from other midstream energy companies;
|
•
|
regulatory action affecting the supply of or demand for natural gas, the rates we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and
|
•
|
prevailing economic conditions.
|
•
|
our level of capital expenditures;
|
•
|
our level of operating and maintenance and general and administrative costs;
|
•
|
our debt service requirements and other liabilities;
|
•
|
fluctuations in our working capital needs;
|
•
|
our ability to borrow funds and access capital markets;
|
•
|
our treatment as a flow-through entity for U.S. federal income tax purposes;
|
•
|
restrictions contained in debt agreements to which we are a party or with respect to convertible preferred units we have agreed to issue; and
|
•
|
the amount of cash reserves established by our general partner.
|
•
|
incur additional indebtedness or guarantee other indebtedness;
|
•
|
grant liens to secure obligations other than our obligations under the Notes or RCF or agree to restrictions on our ability to grant additional liens to secure our obligations under the Notes or RCF;
|
•
|
engage in transactions with affiliates;
|
•
|
make any material change to the nature of our business from the midstream energy business; or
|
•
|
enter into a merger, consolidate, liquidate, wind up or dissolve.
|
•
|
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
|
•
|
our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flows required to make interest payments on our debt;
|
•
|
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
|
•
|
our flexibility in responding to changing business and economic conditions may be limited.
|
•
|
mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies;
|
•
|
an inability to successfully integrate the acquired assets or businesses;
|
•
|
the assumption of unknown liabilities;
|
•
|
limitations on rights to indemnity from the seller;
|
•
|
mistaken assumptions about the overall costs of equity or debt;
|
•
|
the diversion of management’s and employees’ attention from other business concerns;
|
•
|
unforeseen difficulties operating in new geographic areas; and
|
•
|
customer or key employee losses at the acquired businesses.
|
•
|
damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;
|
•
|
inadvertent damage from construction, farm and utility equipment;
|
•
|
leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;
|
•
|
leaks of natural gas containing hazardous quantities of hydrogen sulfide;
|
•
|
fires and explosions (for example, see
General Trends and Outlook
, under Part II, Item 7 of this Form 10-K for a discussion of the incident at our DBM complex); and
|
•
|
other hazards that could also result in personal injury, loss of life, pollution, natural resource damages and/or suspension of operations.
|
•
|
Neither our partnership agreement nor any other agreement requires Anadarko to pursue a business strategy that favors us.
|
•
|
Anadarko is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to parties other than us.
|
•
|
Our general partner is allowed to take into account the interests of parties other than us, such as Anadarko, in resolving conflicts of interest.
|
•
|
The officers of our general partner will also devote significant time to the business of Anadarko and will be compensated by Anadarko accordingly.
|
•
|
Our partnership agreement limits the liability of and reduces the default state law fiduciary 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 under state law.
|
•
|
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
|
•
|
Our general partner determines the amount and timing of asset purchases and sales, 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 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.
|
•
|
Our general partner determines which costs incurred by it are reimbursable by us.
|
•
|
Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make IDR payments.
|
•
|
Our partnership agreement permits us to classify up to $31.8 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of the general partner interest or the IDRs.
|
•
|
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 intends to limit its liability regarding our contractual and other obligations.
|
•
|
Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.
|
•
|
Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.
|
•
|
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
|
•
|
Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to the IDRs without the approval of the Special Committee of the Board of Directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
|
•
|
how to allocate corporate opportunities among us and its affiliates;
|
•
|
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;
|
•
|
whether to elect to reset target distribution levels; and
|
•
|
whether to consent to any merger or consolidation of the Partnership or amendment to the partnership agreement.
|
•
|
provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
|
•
|
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 such decisions are made in good faith, meaning that it believed that the decision was in the best interest of the Partnership;
|
•
|
provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
|
•
|
provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is any of the following:
|
(a)
|
approved by the Special Committee of the Board of Directors of our general partner, although our general partner is not obligated to seek such approval;
|
(b)
|
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
|
(c)
|
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
|
(d)
|
fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
|
•
|
our existing unitholders’ proportionate ownership interest in us will decrease;
|
•
|
the amount of cash available for distribution on each unit may decrease;
|
•
|
the ratio of taxable income to distributions may increase;
|
•
|
the relative voting strength of each previously outstanding unit may be diminished; and
|
•
|
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
|
•
|
such unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
|
•
|
changes in investor or analyst estimates of Anadarko’s and our financial performance or our future distribution growth;
|
•
|
the public’s reaction to Anadarko’s or our press releases, announcements and filings with the SEC;
|
•
|
legislative or regulatory changes affecting our status as a partnership for federal income tax purposes;
|
•
|
fluctuations in broader securities market prices and volumes, particularly among securities of midstream companies and securities of publicly traded limited partnerships;
|
•
|
changes in market valuations of similar companies;
|
•
|
departures of key personnel;
|
•
|
commencement of or involvement in litigation;
|
•
|
variations in our quarterly results of operations or those of midstream companies;
|
•
|
variations in the amount of our quarterly cash distributions;
|
•
|
future issuances and sales of our common units; and
|
•
|
changes in general conditions in the U.S. economy, financial markets or the midstream industry.
|
|
Fourth
Quarter
|
|
Third
Quarter
|
|
Second
Quarter
|
|
First
Quarter
|
||||||||
2015
|
|
|
|
|
|
|
|
||||||||
High Price
|
$
|
54.35
|
|
|
$
|
65.23
|
|
|
$
|
74.30
|
|
|
$
|
74.45
|
|
Low Price
|
36.70
|
|
|
43.88
|
|
|
62.21
|
|
|
62.71
|
|
||||
Distribution per common unit
|
0.800
|
|
|
0.775
|
|
|
0.750
|
|
|
0.725
|
|
||||
2014
|
|
|
|
|
|
|
|
||||||||
High Price
|
$
|
75.29
|
|
|
$
|
79.81
|
|
|
$
|
76.57
|
|
|
$
|
66.50
|
|
Low Price
|
60.09
|
|
|
71.15
|
|
|
65.51
|
|
|
58.50
|
|
||||
Distribution per common unit
|
0.700
|
|
|
0.675
|
|
|
0.650
|
|
|
0.625
|
|
|
|
Acquisition Date
|
|
Percentage Acquired
|
|
Affiliate or Third-party Acquisition
|
|
Initial assets
(1)
|
|
05/14/2008
|
|
100
|
%
|
|
Anadarko
|
Powder River assets
(2)
|
|
12/19/2008
|
|
Various
(2)
|
|
|
Anadarko
|
Chipeta
|
|
07/01/2009
|
|
51
|
%
|
|
Anadarko
|
Granger
|
|
01/29/2010
|
|
100
|
%
|
|
Anadarko
|
Wattenberg
|
|
08/02/2010
|
|
100
|
%
|
|
Anadarko
|
White Cliffs
(3)
|
|
09/28/2010
|
|
10
|
%
|
|
Various
(3)
|
Platte Valley
|
|
02/28/2011
|
|
100
|
%
|
|
Third party
|
Bison
|
|
07/08/2011
|
|
100
|
%
|
|
Anadarko
|
MGR
|
|
01/13/2012
|
|
100
|
%
|
|
Anadarko
|
Chipeta
(4)
|
|
08/01/2012
|
|
24
|
%
|
|
Anadarko
|
Non-Operated Marcellus Interest
|
|
03/01/2013
|
|
33.75
|
%
|
|
Anadarko
|
Anadarko-Operated Marcellus Interest
|
|
03/08/2013
|
|
33.75
|
%
|
|
Third party
|
Mont Belvieu JV
|
|
06/05/2013
|
|
25
|
%
|
|
Third party
|
OTTCO
|
|
09/03/2013
|
|
100
|
%
|
|
Third party
|
TEFR Interests
(5)
|
|
03/03/2014
|
|
Various
(5)
|
|
|
Anadarko
|
DBM
|
|
11/25/2014
|
|
100
|
%
|
|
Third party
|
DBJV system
|
|
03/02/2015
|
|
50
|
%
|
|
Anadarko
|
(1)
|
Concurrently with the closing of our IPO, Anadarko contributed the initial assets to us.
|
(2)
|
Acquired the Powder River assets, which included (i) the Hilight system, (ii) a 50% interest in the Newcastle system and (iii) a 14.81% membership interest in Fort Union.
|
(3)
|
Acquired a 10% interest in White Cliffs, which consisted of a 9.6% third-party interest and a 0.4% interest from Anadarko.
|
(4)
|
Acquired Anadarko’s then-remaining 24% membership interest in Chipeta, receiving distributions related to the additional interest effective July 1, 2012.
|
(5)
|
Acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP.
|
thousands except per-unit data, throughput, Adjusted gross margin per Mcf and Adjusted gross margin per Bbl
|
Summary Financial Information
|
||||||||||||||||||
2015
|
|
2014
(1)
|
|
2013
(1)
|
|
2012
(1)
|
|
2011
(1)
|
|||||||||||
Statement of Income Data (for the year ended):
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
$
|
1,561,372
|
|
|
$
|
1,382,868
|
|
|
$
|
1,085,482
|
|
|
$
|
925,805
|
|
|
$
|
875,817
|
|
Operating income (loss)
|
37,534
|
|
|
478,528
|
|
|
327,259
|
|
|
198,197
|
|
|
245,566
|
|
|||||
Net income (loss)
|
(63,437
|
)
|
|
407,867
|
|
|
289,539
|
|
|
151,391
|
|
|
206,327
|
|
|||||
Net income attributable to noncontrolling interest
|
10,101
|
|
|
14,025
|
|
|
10,816
|
|
|
14,890
|
|
|
14,103
|
|
|||||
Net income (loss) attributable to Western Gas Partners, LP
|
(73,538
|
)
|
|
393,842
|
|
|
278,723
|
|
|
136,501
|
|
|
192,224
|
|
|||||
General partner interest in net income (loss)
(2)
|
180,996
|
|
|
120,980
|
|
|
69,633
|
|
|
28,089
|
|
|
8,599
|
|
|||||
Limited partners’ interest in net income (loss)
(2)
|
(256,276
|
)
|
|
256,509
|
|
|
200,866
|
|
|
78,863
|
|
|
131,560
|
|
|||||
Net income (loss) per common unit (basic)
(2)
|
(1.95
|
)
|
|
2.13
|
|
|
1.83
|
|
|
0.84
|
|
|
1.64
|
|
|||||
Net income (loss) per common unit (diluted)
(2)
|
(1.95
|
)
|
|
2.12
|
|
|
1.83
|
|
|
0.84
|
|
|
1.64
|
|
|||||
Net income (loss) per subordinated unit (basic and diluted)
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.28
|
|
|||||
Distributions per unit
|
3.050
|
|
|
2.650
|
|
|
2.280
|
|
|
1.960
|
|
|
1.655
|
|
|||||
Balance Sheet Data (at year end):
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
$
|
6,707,262
|
|
|
$
|
6,954,518
|
|
|
$
|
4,765,433
|
|
|
$
|
4,002,919
|
|
|
$
|
3,046,651
|
|
Total long-term liabilities
|
3,020,600
|
|
|
2,580,310
|
|
|
1,566,545
|
|
|
1,307,001
|
|
|
869,211
|
|
|||||
Total equity and partners’ capital
|
3,487,430
|
|
|
4,134,375
|
|
|
2,993,199
|
|
|
2,500,020
|
|
|
2,046,676
|
|
|||||
Cash Flow Data (for the year ended):
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash flows provided by (used in):
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
$
|
669,609
|
|
|
$
|
580,209
|
|
|
$
|
492,605
|
|
|
$
|
343,901
|
|
|
$
|
310,600
|
|
Investing activities
|
(466,424
|
)
|
|
(2,670,998
|
)
|
|
(1,688,523
|
)
|
|
(1,430,815
|
)
|
|
(512,095
|
)
|
|||||
Financing activities
|
(172,206
|
)
|
|
2,057,115
|
|
|
876,665
|
|
|
1,280,335
|
|
|
400,980
|
|
|||||
Capital expenditures
|
(601,828
|
)
|
|
(722,260
|
)
|
|
(681,382
|
)
|
|
(711,399
|
)
|
|
(175,980
|
)
|
|||||
Throughput (MMcf/d except throughput measured in barrels):
|
|||||||||||||||||||
Total throughput for natural gas assets
|
3,996
|
|
|
3,723
|
|
|
3,409
|
|
|
3,055
|
|
|
2,731
|
|
|||||
Throughput attributable to noncontrolling interest for natural gas assets
|
142
|
|
|
165
|
|
|
168
|
|
|
228
|
|
|
242
|
|
|||||
Total throughput attributable to Western Gas Partners, LP for natural gas assets
(3)
|
3,854
|
|
|
3,558
|
|
|
3,241
|
|
|
2,827
|
|
|
2,489
|
|
|||||
Throughput (MBbls/d) for crude/NGL assets
(4)
|
138
|
|
|
116
|
|
|
40
|
|
|
31
|
|
|
28
|
|
|||||
Key Performance Metrics (for the year ended):
|
|
|
|
|
|
|
|
|
|
||||||||||
Adjusted gross margin attributable to
Western Gas Partners, LP for natural gas assets
(5) (6)
|
$
|
971,639
|
|
|
$
|
876,210
|
|
|
$
|
681,307
|
|
|
$
|
556,172
|
|
|
$
|
518,459
|
|
Adjusted gross margin for crude/NGL assets
(5) (7)
|
88,642
|
|
|
73,714
|
|
|
15,274
|
|
|
13,221
|
|
|
9,497
|
|
|||||
Adjusted gross margin per Mcf attributable to
Western Gas Partners, LP for natural gas assets
(8)
|
0.69
|
|
|
0.67
|
|
|
0.55
|
|
|
0.54
|
|
|
0.57
|
|
|||||
Adjusted gross margin per Bbl for crude/NGL assets
(9)
|
1.76
|
|
|
1.75
|
|
|
1.05
|
|
|
1.17
|
|
|
0.94
|
|
|||||
Adjusted EBITDA attributable to
Western Gas Partners, LP
(5)
|
757,966
|
|
|
679,352
|
|
|
469,340
|
|
|
383,755
|
|
|
362,468
|
|
|||||
Distributable cash flow
(5)
|
636,363
|
|
|
561,181
|
|
|
386,853
|
|
|
312,892
|
|
|
317,715
|
|
(1)
|
Financial information has been recast to include the financial position and results attributable to the DBJV system. See
Note 1—Summary of Significant Accounting Policies
and
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K.
|
(2)
|
Net income (loss) earned on and subsequent to the date of our acquisitions of Partnership assets is allocated to the general partner and the limited partners, including any subordinated and Class C unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to incentive distributions allocable to the general partner. For periods prior to our acquisition of the Partnership assets, all income is attributed to Anadarko. All subordinated units were converted into common units on August 15, 2011, on a one-for-one basis. For purposes of calculating net income (loss) per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. See
Note 4—Equity and Partners’ Capital
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K.
|
(3)
|
Includes affiliate, third-party and equity investment throughput, excluding the noncontrolling interest owners’ proportionate share of throughput.
|
(4)
|
Represents total throughput measured in barrels consisting of throughput from our Chipeta NGL pipeline, our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput and our 33.33% share of average FRP throughput.
|
(5)
|
Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are not defined in GAAP. For definitions and reconciliations of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see the caption
How We Evaluate Our Operations
under Part II, Item 7 of this Form 10-K.
|
(6)
|
Calculated as total revenues and other for natural gas assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for natural gas assets, plus distributions from our equity investments in Fort Union and Rendezvous, which are measured in Mcf, and excluding the noncontrolling interest owners’ proportionate share of revenue and cost of product.
|
(7)
|
Calculated as total revenues and other for crude/NGL assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for crude/NGL assets, plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, and the TEFR Interests, which are measured in barrels.
|
(8)
|
Average for period. Calculated as Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (as defined above) divided by total throughput (MMcf/d) attributable to Western Gas Partners, LP for natural gas assets.
|
(9)
|
Average for period. Calculated as Adjusted gross margin for crude/NGL assets (as defined above), divided by total throughput (MBbls/d) for crude/NGL assets.
|
|
|
Owned and
Operated
|
|
Operated
Interests
|
|
Non-Operated
Interests
|
|
Equity
Interests
|
||||
Natural gas gathering systems
|
|
12
|
|
|
2
|
|
|
5
|
|
|
2
|
|
Natural gas treating facilities
|
|
12
|
|
|
4
|
|
|
—
|
|
|
3
|
|
Natural gas processing plants/trains
(1)
|
|
18
|
|
|
5
|
|
|
—
|
|
|
2
|
|
NGL pipelines
|
|
2
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Natural gas pipelines
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Oil pipeline
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
(1)
|
On December 3, 2015, an incident occurred at our DBM complex. See below and
General Trends and Outlook
within this Item 7.
|
•
|
On December 3, 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex, damaging the liquid handling facilities and amine treating units at the complex inlet. There was no damage to Trains IV and V, which were under construction at the time of the incident; however, Trains II and III sustained some damage. See
General Trends and Outlook
within this Item 7 for additional information.
|
•
|
We completed the acquisition of DBJV from Anadarko. See
Acquisitions and Divestitures
under Part I, Items 1 and 2 of this Form 10-K for additional information.
|
•
|
In July 2015, we closed on the sale of our Dew and Pinnacle systems, which resulted in net proceeds of
$145.6 million
, after closing adjustments, and a net gain on divestiture of
$77.3 million
.
|
•
|
We completed the offering of $500.0 million aggregate principal amount of 2025 Notes in June 2015. Net proceeds were used to repay a portion of the amount outstanding under our RCF. See
Liquidity and Capital Resources
within this
Item 7
for additional information.
|
•
|
In June 2015, we completed the construction and commenced operations of Lancaster Train II, a 300 MMcf/d processing plant located within the DJ Basin complex in Northeast Colorado.
|
•
|
We issued
873,525
common units to the public under our $500.0 million COP, generating net proceeds of
$57.4 million
. Net proceeds were used for general partnership purposes, including funding capital expenditures. See
Equity Offerings
under Part I, Items 1 and 2 of this Form 10-K for additional information.
|
•
|
We raised our distribution to
$0.800
per unit for the
fourth
quarter of
2015
, representing a
3%
increase
over the distribution for the
third
quarter of 2015 and a
14%
increase
over the distribution for the
fourth
quarter of
2014
.
|
•
|
Throughput attributable to Western Gas Partners, LP for natural gas assets totaled
3,854
MMcf/d for the
year ended December 31, 2015
, representing an
8%
increase
compared to the year ended December 31, 2014.
|
•
|
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (as defined under the caption
How We Evaluate Our Operations
within this
Item 7
) averaged
$0.69
per Mcf for the
year ended December 31, 2015
, representing a
3%
increase
compared to the year ended December 31, 2014.
|
•
|
Adjusted gross margin for crude/NGL assets (as defined under the caption
How We Evaluate Our Operations
within this
Item 7
) averaged
$1.76
per Bbl for the
year ended December 31, 2015
, representing a
1%
increase
compared to the year ended December 31, 2014.
|
•
|
expenses associated with annual and quarterly reporting;
|
•
|
tax return and Schedule K-1 preparation and distribution expenses;
|
•
|
expenses associated with listing on the NYSE; and
|
•
|
independent auditor fees, legal expenses, investor relations expenses, director fees, and registrar and transfer agent fees.
|
•
|
our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;
|
•
|
the ability of our assets to generate cash flow to make distributions; and
|
•
|
the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2015
|
|
2014
|
|
2013
|
||||||
Reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP to Operating income (loss)
|
|
|
|
|
|
|
||||||
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets
|
|
$
|
971,639
|
|
|
$
|
876,210
|
|
|
$
|
681,307
|
|
Adjusted gross margin for crude/NGL assets
|
|
88,642
|
|
|
73,714
|
|
|
15,274
|
|
|||
Adjusted gross margin attributable to Western Gas Partners, LP
|
|
1,060,281
|
|
|
949,924
|
|
|
696,581
|
|
|||
Adjusted gross margin attributable to noncontrolling interest
|
|
16,779
|
|
|
20,183
|
|
|
17,416
|
|
|||
Gain on divestiture and other, net
(1)
|
|
57,020
|
|
|
—
|
|
|
—
|
|
|||
Equity income, net
|
|
71,251
|
|
|
57,836
|
|
|
22,948
|
|
|||
Reimbursed electricity-related charges recorded as revenues
|
|
54,175
|
|
|
39,338
|
|
|
20,450
|
|
|||
Less:
|
|
|
|
|
|
|
||||||
Distributions from equity investees
|
|
98,298
|
|
|
81,022
|
|
|
22,136
|
|
|||
Operation and maintenance
|
|
296,774
|
|
|
255,844
|
|
|
201,759
|
|
|||
General and administrative
|
|
38,108
|
|
|
36,223
|
|
|
31,353
|
|
|||
Property and other taxes
|
|
30,533
|
|
|
26,066
|
|
|
23,806
|
|
|||
Depreciation and amortization
|
|
244,163
|
|
|
186,514
|
|
|
149,815
|
|
|||
Impairments
|
|
514,096
|
|
|
3,084
|
|
|
1,267
|
|
|||
Operating income (loss)
|
|
$
|
37,534
|
|
|
$
|
478,528
|
|
|
$
|
327,259
|
|
(1)
|
See
Note 1—Summary of Significant Accounting Policies
and
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under
Part II
,
Item 8
of this Form
10-K
.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2015
|
|
2014
|
|
2013
|
||||||
Reconciliation of Adjusted EBITDA attributable to Western Gas Partners, LP to Net income (loss) attributable to Western Gas Partners, LP
|
|
|
|
|
|
|
||||||
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
$
|
757,966
|
|
|
$
|
679,352
|
|
|
$
|
469,340
|
|
Less:
|
|
|
|
|
|
|
||||||
Distributions from equity investees
|
|
98,298
|
|
|
81,022
|
|
|
22,136
|
|
|||
Non-cash equity-based compensation expense
|
|
4,402
|
|
|
4,095
|
|
|
3,575
|
|
|||
Interest expense
|
|
113,872
|
|
|
76,766
|
|
|
51,797
|
|
|||
Income tax expense
|
|
5,285
|
|
|
11,659
|
|
|
6,524
|
|
|||
Depreciation and amortization
(1)
|
|
241,556
|
|
|
183,945
|
|
|
147,274
|
|
|||
Impairments
|
|
514,096
|
|
|
3,084
|
|
|
1,267
|
|
|||
Other expense
(1)
|
|
1,290
|
|
|
—
|
|
|
175
|
|
|||
Add:
|
|
|
|
|
|
|
||||||
Gain on divestiture and other, net
(2)
|
|
57,020
|
|
|
—
|
|
|
—
|
|
|||
Equity income, net
|
|
71,251
|
|
|
57,836
|
|
|
22,948
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Other income
(1) (3)
|
|
219
|
|
|
325
|
|
|
419
|
|
|||
Income tax benefit
|
|
1,905
|
|
|
—
|
|
|
1,864
|
|
|||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
(73,538
|
)
|
|
$
|
393,842
|
|
|
$
|
278,723
|
|
Reconciliation of Adjusted EBITDA attributable to Western Gas Partners, LP to Net cash provided by operating activities
|
|
|
|
|
|
|
||||||
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
$
|
757,966
|
|
|
$
|
679,352
|
|
|
$
|
469,340
|
|
Adjusted EBITDA attributable to noncontrolling interest
|
|
12,699
|
|
|
16,583
|
|
|
13,348
|
|
|||
Interest income (expense), net
|
|
(96,972
|
)
|
|
(59,866
|
)
|
|
(34,897
|
)
|
|||
Uncontributed cash-based compensation awards
|
|
(214
|
)
|
|
(175
|
)
|
|
(54
|
)
|
|||
Accretion and amortization of long-term obligations, net
|
|
17,698
|
|
|
2,736
|
|
|
2,449
|
|
|||
Current income tax benefit (expense)
|
|
(1,448
|
)
|
|
1,666
|
|
|
35,375
|
|
|||
Other income (expense), net
(3)
|
|
(619
|
)
|
|
336
|
|
|
253
|
|
|||
Distributions from equity investments in excess of cumulative earnings
|
|
(16,244
|
)
|
|
(18,055
|
)
|
|
(4,438
|
)
|
|||
Changes in operating working capital:
|
|
|
|
|
|
|
||||||
Accounts receivable, net
|
|
(5,614
|
)
|
|
(6,691
|
)
|
|
(13,936
|
)
|
|||
Accounts and imbalance payables and accrued liabilities, net
|
|
3,154
|
|
|
(39,162
|
)
|
|
28,867
|
|
|||
Other
|
|
(797
|
)
|
|
3,485
|
|
|
(3,702
|
)
|
|||
Net cash provided by operating activities
|
|
$
|
669,609
|
|
|
$
|
580,209
|
|
|
$
|
492,605
|
|
Cash flow information of Western Gas Partners, LP
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
|
$
|
669,609
|
|
|
$
|
580,209
|
|
|
$
|
492,605
|
|
Net cash used in investing activities
|
|
(466,424
|
)
|
|
(2,670,998
|
)
|
|
(1,688,523
|
)
|
|||
Net cash provided by (used in) financing activities
|
|
(172,206
|
)
|
|
2,057,115
|
|
|
876,665
|
|
(1)
|
Includes our 75% share of depreciation and amortization; other expense; and other income attributable to the Chipeta complex. For the year ended December 31, 2015, other expense also includes $0.4 million of lower of cost or market inventory adjustments at our DBM complex.
|
(2)
|
See
Note 1—Summary of Significant Accounting Policies
and
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under
Part II
,
Item 8
of this Form
10-K
.
|
(3)
|
Excludes income of
zero
,
$0.5 million
and
$1.6 million
for the
years ended December 31, 2015
,
2014
and 2013, respectively, related to a component of a gas processing agreement accounted for as a capital lease.
|
|
|
Year Ended December 31,
|
||||||||||
thousands except Coverage ratio
|
|
2015
|
|
2014
|
|
2013
|
||||||
Reconciliation of Distributable cash flow to Net income (loss) attributable to Western Gas Partners, LP and calculation of the Coverage ratio
|
|
|
|
|
|
|
||||||
Distributable cash flow
|
|
$
|
636,363
|
|
|
$
|
561,181
|
|
|
$
|
386,853
|
|
Less:
|
|
|
|
|
|
|
||||||
Distributions from equity investees
|
|
98,298
|
|
|
81,022
|
|
|
22,136
|
|
|||
Non-cash equity-based compensation expense
|
|
4,402
|
|
|
4,095
|
|
|
3,575
|
|
|||
Interest expense, net (non-cash settled)
(1)
|
|
14,400
|
|
|
—
|
|
|
—
|
|
|||
Income tax (benefit) expense
|
|
3,380
|
|
|
11,659
|
|
|
4,660
|
|
|||
Depreciation and amortization
(2)
|
|
241,556
|
|
|
183,945
|
|
|
147,274
|
|
|||
Impairments
|
|
514,096
|
|
|
3,084
|
|
|
1,267
|
|
|||
Above-market component of swap extensions with Anadarko
(3)
|
|
18,449
|
|
|
—
|
|
|
—
|
|
|||
Other expense
(2)
|
|
1,290
|
|
|
—
|
|
|
175
|
|
|||
Add:
|
|
|
|
|
|
|
||||||
Gain on divestiture and other, net
(4)
|
|
57,020
|
|
|
—
|
|
|
—
|
|
|||
Equity income, net
|
|
71,251
|
|
|
57,836
|
|
|
22,948
|
|
|||
Cash paid for maintenance capital expenditures
(2)
|
|
49,300
|
|
|
48,563
|
|
|
35,093
|
|
|||
Capitalized interest
(5)
|
|
8,318
|
|
|
9,832
|
|
|
11,945
|
|
|||
Cash paid for (reimbursement of) income taxes
|
|
(138
|
)
|
|
(90
|
)
|
|
552
|
|
|||
Other income
(2) (6)
|
|
219
|
|
|
325
|
|
|
419
|
|
|||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
(73,538
|
)
|
|
$
|
393,842
|
|
|
$
|
278,723
|
|
Distributions declared
(7)
|
|
|
|
|
|
|
||||||
Limited partners
|
|
$
|
392,077
|
|
|
|
|
|
||||
General partner
|
|
179,610
|
|
|
|
|
|
|||||
Total
|
|
$
|
571,687
|
|
|
|
|
|
||||
Coverage ratio
|
|
1.11
|
|
x
|
|
|
|
(1)
|
Includes accretion expense related to the Deferred purchase price obligation - Anadarko. See
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under
Part II
,
Item 8
of this Form
10-K
.
|
(2)
|
Includes our 75% share of depreciation and amortization; other expense; cash paid for maintenance capital expenditures; and other income attributable to the Chipeta complex. For the year ended December 31, 2015, other expense also includes $0.4 million of lower of cost or market inventory adjustments at our DBM complex.
|
(3)
|
See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under
Part II
,
Item 8
of this Form
10-K
.
|
(4)
|
See
Note 1—Summary of Significant Accounting Policies
and
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under
Part II
,
Item 8
of this Form
10-K
.
|
(5)
|
For the year ended December 31, 2013, includes capitalized interest of $1.4 million for the construction of the Mont Belvieu JV fractionation trains, reflected as a component of the equity investment balance.
|
(6)
|
Excludes income of
zero
,
$0.5 million
and
$1.6 million
for the
years ended December 31, 2015
,
2014
and 2013, respectively, related to a component of a gas processing agreement accounted for as a capital lease.
|
(7)
|
Reflects cash distributions of
$3.050
per unit declared for the
year ended December 31, 2015
.
|
•
|
DBM acquisition.
In November 2014, we acquired Nuevo Midstream, LLC from a third party. Following the acquisition, we changed the name of Nuevo to Delaware Basin Midstream, LLC. We financed the acquisition with the issuance of $750.0 million of Class C units to a subsidiary of Anadarko, borrowings under our RCF and cash on hand, including the proceeds from the November 2014 equity offering. These assets have been recorded in our consolidated financial statements at their estimated fair values on the acquisition date under the acquisition method of accounting. Results of operations attributable to the DBM acquisition were included in our consolidated statement of income beginning on the acquisition date in the fourth quarter of 2014.
|
•
|
DBJV acquisition.
In March 2015, we acquired Anadarko’s interest in DBJV. We will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. We currently estimate the future payment will be
$282.8 million
, the net present value of which was
$174.3 million
as of the acquisition date. As of
December 31, 2015
, the net present value of this obligation was
$188.7 million
and has been recorded on the consolidated balance sheet under Deferred purchase price obligation - Anadarko. Accretion expense was
$14.4 million
for the year ended
December 31, 2015
, and
zero
for each of the years ended
December 31, 2014
and
2013
, and has been recorded as a charge to interest expense.
|
•
|
Dew and Pinnacle divestiture.
In July 2015, the Dew and Pinnacle systems in East Texas were sold to a third party for net proceeds of $145.6 million, after closing adjustments, resulting in a net gain on sale of $77.3 million recorded as Gain on divestiture and other, net in the consolidated statements of income.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2015
|
|
2014
|
|
2013
|
||||||
Gathering, processing and transportation of natural gas and natural gas liquids
|
|
$
|
938,121
|
|
|
$
|
745,145
|
|
|
$
|
530,993
|
|
Natural gas, natural gas liquids and drip condensate sales
|
|
617,949
|
|
|
624,233
|
|
|
548,508
|
|
|||
Other
|
|
5,302
|
|
|
13,490
|
|
|
5,981
|
|
|||
Total revenues and other
(1)
|
|
1,561,372
|
|
|
1,382,868
|
|
|
1,085,482
|
|
|||
Equity income, net
|
|
71,251
|
|
|
57,836
|
|
|
22,948
|
|
|||
Total operating expenses
(1)
|
|
1,652,109
|
|
|
962,176
|
|
|
781,171
|
|
|||
Gain on divestiture and other, net
|
|
57,020
|
|
|
—
|
|
|
—
|
|
|||
Operating income (loss)
|
|
37,534
|
|
|
478,528
|
|
|
327,259
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
|
|
(113,872
|
)
|
|
(76,766
|
)
|
|
(51,797
|
)
|
|||
Other income (expense), net
|
|
(619
|
)
|
|
864
|
|
|
1,837
|
|
|||
Income (loss) before income taxes
|
|
(60,057
|
)
|
|
419,526
|
|
|
294,199
|
|
|||
Income tax (benefit) expense
|
|
3,380
|
|
|
11,659
|
|
|
4,660
|
|
|||
Net income (loss)
|
|
(63,437
|
)
|
|
407,867
|
|
|
289,539
|
|
|||
Net income attributable to noncontrolling interest
|
|
10,101
|
|
|
14,025
|
|
|
10,816
|
|
|||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
(73,538
|
)
|
|
$
|
393,842
|
|
|
$
|
278,723
|
|
Key performance metrics
(2)
|
|
|
|
|
|
|
||||||
Adjusted gross margin attributable to Western Gas Partners, LP
|
|
$
|
1,060,281
|
|
|
$
|
949,924
|
|
|
$
|
696,581
|
|
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
757,966
|
|
|
679,352
|
|
|
469,340
|
|
|||
Distributable cash flow
|
|
636,363
|
|
|
561,181
|
|
|
386,853
|
|
(1)
|
Revenues and other include amounts earned from services provided to our affiliates, as well as from the sale of residue, drip condensate and NGLs to our affiliates. Operating expenses include amounts charged by our affiliates for services as well as reimbursement of amounts paid by affiliates to third parties on our behalf. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under
Part II
,
Item 8
of this Form
10-K
.
|
(2)
|
Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow are defined under the caption
How We Evaluate Our Operations–Non-GAAP financial measures
within this
Item 7
.
For reconciliations of Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see
How We Evaluate Our Operations–Reconciliation to GAAP Measures
within this
Item 7
.
|
|
|
Year Ended December 31,
|
|||||||||||||
MMcf/d (except throughput measured in barrels)
|
|
2015
|
|
2014
|
|
Inc/
(Dec)
|
|
2013
|
|
Inc/
(Dec)
|
|||||
Throughput for natural gas assets
|
|
|
|
|
|
|
|
|
|
|
|||||
Gathering, treating and transportation
(1)
|
|
1,487
|
|
|
1,627
|
|
|
(9
|
)%
|
|
1,445
|
|
|
13
|
%
|
Processing
(1)
|
|
2,331
|
|
|
1,925
|
|
|
21
|
%
|
|
1,758
|
|
|
9
|
%
|
Equity investment
(2)
|
|
178
|
|
|
171
|
|
|
4
|
%
|
|
206
|
|
|
(17
|
)%
|
Total throughput for natural gas assets
|
|
3,996
|
|
|
3,723
|
|
|
7
|
%
|
|
3,409
|
|
|
9
|
%
|
Throughput attributable to noncontrolling interest for natural gas assets
|
|
142
|
|
|
165
|
|
|
(14
|
)%
|
|
168
|
|
|
(2
|
)%
|
Total throughput attributable to Western Gas Partners, LP for natural gas assets
(3)
|
|
3,854
|
|
|
3,558
|
|
|
8
|
%
|
|
3,241
|
|
|
10
|
%
|
Total throughput (MBbls/d) for crude/NGL assets
(4)
|
|
138
|
|
|
116
|
|
|
19
|
%
|
|
40
|
|
|
190
|
%
|
(1)
|
The combination of our Wattenberg and Platte Valley systems in 2014 into the entity now referred to as the “DJ Basin complex” (which also includes the Lancaster plant) resulted in the following: (i) the Wattenberg system throughput previously reported as “Gathering, treating and transportation” is now reported as “Processing” for all periods presented, and (ii) beginning in 2014, throughput both gathered and processed by the two systems is no longer separately reported.
|
(2)
|
Represents our 14.81% share of average Fort Union and our 22% share of average Rendezvous throughput. Excludes equity investment throughput measured in barrels (captured in “Total throughput (MBbls/d) for crude/NGL assets” as noted below).
|
(3)
|
Includes affiliate, third-party and equity investment throughput (as equity investment throughput is defined in the above footnote), excluding the noncontrolling interest owner’s proportionate share of throughput.
|
(4)
|
Represents total throughput measured in barrels, consisting of throughput from our Chipeta NGL pipeline, our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput, and our 33.33% share of average FRP throughput.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2015
|
|
2014
|
|
Inc/
(Dec)
|
|
2013
|
|
Inc/
(Dec)
|
||||||||
Gathering, processing and transportation of natural gas and natural gas liquids
|
|
$
|
938,121
|
|
|
$
|
745,145
|
|
|
26
|
%
|
|
$
|
530,993
|
|
|
40
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages and per-unit amounts
|
|
2015
|
|
2014
|
|
Inc/
(Dec)
|
|
2013
|
|
Inc/
(Dec)
|
||||||||
Natural gas sales
(1)
|
|
$
|
242,826
|
|
|
$
|
166,855
|
|
|
46
|
%
|
|
$
|
120,917
|
|
|
38
|
%
|
Natural gas liquids sales
(1)
|
|
338,770
|
|
|
417,473
|
|
|
(19
|
)%
|
|
391,619
|
|
|
7
|
%
|
|||
Drip condensate sales
(1)
|
|
36,353
|
|
|
39,905
|
|
|
(9
|
)%
|
|
35,972
|
|
|
11
|
%
|
|||
Total
|
|
$
|
617,949
|
|
|
$
|
624,233
|
|
|
(1
|
)%
|
|
$
|
548,508
|
|
|
14
|
%
|
Average price per unit
(1)
:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas (per Mcf)
|
|
$
|
3.28
|
|
|
$
|
4.16
|
|
|
(21
|
)%
|
|
$
|
4.54
|
|
|
(8
|
)%
|
Natural gas liquids (per Bbl)
|
|
21.23
|
|
|
43.62
|
|
|
(51
|
)%
|
|
47.69
|
|
|
(9
|
)%
|
|||
Drip condensate (per Bbl)
|
|
45.38
|
|
|
80.68
|
|
|
(44
|
)%
|
|
78.91
|
|
|
2
|
%
|
(1)
|
Excludes amounts considered above market with respect to our swap extensions at the DJ Basin complex beginning July 1, 2015 and at the Hugoton system beginning October 1, 2015. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under
Part II
,
Item 8
of this Form
10-K
.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2015
|
|
2014
|
|
Inc/
(Dec)
|
|
2013
|
|
Inc/
(Dec)
|
||||||||
Equity income, net
|
|
$
|
71,251
|
|
|
$
|
57,836
|
|
|
23
|
%
|
|
$
|
22,948
|
|
|
152
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2015
|
|
2014
|
|
Inc/
(Dec)
|
|
2013
|
|
Inc/
(Dec)
|
||||||||
NGL purchases
(1)
|
|
$
|
249,397
|
|
|
$
|
228,369
|
|
|
9
|
%
|
|
$
|
191,788
|
|
|
19
|
%
|
Residue purchases
(1)
|
|
252,585
|
|
|
186,294
|
|
|
36
|
%
|
|
156,761
|
|
|
19
|
%
|
|||
Other
(1)
|
|
26,453
|
|
|
39,782
|
|
|
(34
|
)%
|
|
24,622
|
|
|
62
|
%
|
|||
Cost of product
|
|
528,435
|
|
|
454,445
|
|
|
16
|
%
|
|
373,171
|
|
|
22
|
%
|
|||
Operation and maintenance
|
|
296,774
|
|
|
255,844
|
|
|
16
|
%
|
|
201,759
|
|
|
27
|
%
|
|||
Total cost of product and operation and maintenance expenses
|
|
$
|
825,209
|
|
|
$
|
710,289
|
|
|
16
|
%
|
|
$
|
574,930
|
|
|
24
|
%
|
(1)
|
Excludes amounts considered above market with respect to our swap extensions at the DJ Basin complex beginning July 1, 2015, and at the Hugoton system beginning October 1, 2015. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under
Part II
,
Item 8
of this Form
10-K
.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2015
|
|
2014
|
|
Inc/
(Dec)
|
|
2013
|
|
Inc/
(Dec)
|
||||||||
General and administrative
|
|
$
|
38,108
|
|
|
$
|
36,223
|
|
|
5
|
%
|
|
$
|
31,353
|
|
|
16
|
%
|
Property and other taxes
|
|
30,533
|
|
|
26,066
|
|
|
17
|
%
|
|
23,806
|
|
|
9
|
%
|
|||
Depreciation and amortization
|
|
244,163
|
|
|
186,514
|
|
|
31
|
%
|
|
149,815
|
|
|
24
|
%
|
|||
Impairments
|
|
514,096
|
|
|
3,084
|
|
|
NM
|
|
|
1,267
|
|
|
143
|
%
|
|||
Total general and administrative, depreciation and amortization, impairments and other expenses
|
|
$
|
826,900
|
|
|
$
|
251,887
|
|
|
NM
|
|
|
$
|
206,241
|
|
|
22
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2015
|
|
2014
|
|
Inc/
(Dec)
|
|
2013
|
|
Inc/
(Dec)
|
||||||||
Note receivable – Anadarko
|
|
$
|
16,900
|
|
|
$
|
16,900
|
|
|
—
|
%
|
|
$
|
16,900
|
|
|
—
|
%
|
Interest income – affiliates
|
|
$
|
16,900
|
|
|
$
|
16,900
|
|
|
—
|
%
|
|
$
|
16,900
|
|
|
—
|
%
|
Third parties
|
|
|
|
|
|
|
|
|
|
|
||||||||
Long-term debt
|
|
$
|
(102,058
|
)
|
|
$
|
(81,495
|
)
|
|
25
|
%
|
|
$
|
(59,293
|
)
|
|
37
|
%
|
Amortization of debt issuance costs and commitment fees
|
|
(5,734
|
)
|
|
(5,103
|
)
|
|
12
|
%
|
|
(4,449
|
)
|
|
15
|
%
|
|||
Capitalized interest
|
|
8,318
|
|
|
9,832
|
|
|
(15
|
)%
|
|
11,945
|
|
|
(18
|
)%
|
|||
Affiliates
|
|
|
|
|
|
|
|
|
|
|
||||||||
Deferred purchase price obligation – Anadarko
(1)
|
|
(14,398
|
)
|
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
|||
Interest expense
|
|
$
|
(113,872
|
)
|
|
$
|
(76,766
|
)
|
|
48
|
%
|
|
$
|
(51,797
|
)
|
|
48
|
%
|
(1)
|
See
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under
Part II
,
Item 8
of this Form
10-K
for a discussion of the accretion and present value of the Deferred purchase price obligation - Anadarko.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2015
|
|
2014
|
|
Inc/
(Dec)
|
|
2013
|
|
Inc/
(Dec)
|
||||||||
Income (loss) before income taxes
|
|
$
|
(60,057
|
)
|
|
$
|
419,526
|
|
|
(114
|
)%
|
|
$
|
294,199
|
|
|
43
|
%
|
Income tax (benefit) expense
|
|
3,380
|
|
|
11,659
|
|
|
(71
|
)%
|
|
4,660
|
|
|
150
|
%
|
|||
Effective tax rate
|
|
NM
|
|
|
3
|
%
|
|
|
|
2
|
%
|
|
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages and per-unit amounts
|
|
2015
|
|
2014
|
|
Inc/
(Dec)
|
|
2013
|
|
Inc/
(Dec)
|
||||||||
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets
(1)
|
|
$
|
971,639
|
|
|
$
|
876,210
|
|
|
11
|
%
|
|
$
|
681,307
|
|
|
29
|
%
|
Adjusted gross margin for crude/NGL assets
(2)
|
|
88,642
|
|
|
73,714
|
|
|
20
|
%
|
|
15,274
|
|
|
NM
|
|
|||
Adjusted gross margin attributable to Western Gas Partners, LP
(3)
|
|
1,060,281
|
|
|
949,924
|
|
|
12
|
%
|
|
696,581
|
|
|
36
|
%
|
|||
Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets
(4)
|
|
0.69
|
|
|
0.67
|
|
|
3
|
%
|
|
0.55
|
|
|
22
|
%
|
|||
Adjusted gross margin per Bbl for crude/NGL assets
(5)
|
|
1.76
|
|
|
1.75
|
|
|
1
|
%
|
|
1.05
|
|
|
67
|
%
|
|||
Adjusted EBITDA attributable to Western Gas Partners, LP
(3)
|
|
757,966
|
|
|
679,352
|
|
|
12
|
%
|
|
469,340
|
|
|
45
|
%
|
|||
Distributable cash flow
(3)
|
|
636,363
|
|
|
561,181
|
|
|
13
|
%
|
|
386,853
|
|
|
45
|
%
|
(1)
|
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets is calculated as total revenues and other for natural gas assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for natural gas assets, plus distributions from our equity investments in Fort Union and Rendezvous, and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. See the reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets to its most comparable GAAP measure under
How We Evaluate Our Operations—Reconciliation to GAAP measures
within this Item 7.
|
(2)
|
Adjusted gross margin for crude/NGL assets is calculated as total revenues and other for crude/NGL assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for crude/NGL assets, plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, and the TEFR Interests. See the reconciliation of Adjusted gross margin for crude/NGL assets to its most comparable GAAP measure under
How We Evaluate Our Operations—Reconciliation to GAAP measures
within this Item 7.
|
(3)
|
For a reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow to the most directly comparable financial measure calculated and presented in accordance with GAAP, see
How We Evaluate Our Operations—Reconciliation to GAAP measures
within this Item 7.
|
(4)
|
Average for period. Calculated as Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets, divided by total throughput (MMcf/d) attributable to Western Gas Partners, LP for natural gas assets.
|
(5)
|
Average for period. Calculated as Adjusted gross margin for crude/NGL assets, divided by total throughput (MBbls/d) for crude/NGL assets.
|
•
|
maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, such as to replace system components and equipment that have been subject to significant use over time, become obsolete or reached the end of their useful lives, to remain in compliance with regulatory or legal requirements or to complete additional well connections to maintain existing system throughput and related cash flows; or
|
•
|
expansion capital expenditures, which include expenditures to construct new midstream infrastructure and those expenditures incurred to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system throughput.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2015
|
|
2014
|
|
2013
|
||||||
Acquisitions
|
|
$
|
16,178
|
|
|
$
|
1,902,520
|
|
|
$
|
716,985
|
|
|
|
|
|
|
|
|
||||||
Expansion capital expenditures
|
|
$
|
552,190
|
|
|
$
|
673,241
|
|
|
$
|
646,209
|
|
Maintenance capital expenditures
|
|
49,638
|
|
|
49,019
|
|
|
35,173
|
|
|||
Total capital expenditures
(1) (2)
|
|
$
|
601,828
|
|
|
$
|
722,260
|
|
|
$
|
681,382
|
|
|
|
|
|
|
|
|
||||||
Capital incurred
(2) (3)
|
|
$
|
533,673
|
|
|
$
|
753,425
|
|
|
$
|
661,640
|
|
(1)
|
Maintenance capital expenditures for the years ended
December 31, 2015
,
2014
and
2013
, are presented net of
$0.5 million
,
$0.2 million
and
$0.6 million
, respectively, of contributions in aid of construction costs from affiliates. Capital expenditures for the years ended December 31, 2014 and 2013, included $49.4 million and $35.5 million, respectively, of pre-acquisition capital expenditures for the DBJV system.
|
(2)
|
Includes the noncontrolling interest owner’s share of Chipeta’s capital expenditures for all periods presented. For the years ended
December 31, 2015
,
2014
and
2013
, included
$8.3 million
,
$9.8 million
and $10.6 million, respectively, of capitalized interest.
|
(3)
|
Capital incurred for the years ended December 31, 2014 and 2013, included $58.1 million and $33.4 million, respectively, of pre-acquisition capital incurred for the DBJV system.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2015
|
|
2014
|
|
2013
|
||||||
Net cash provided by (used in):
|
|
|
|
|
|
|
||||||
Operating activities
|
|
$
|
669,609
|
|
|
$
|
580,209
|
|
|
$
|
492,605
|
|
Investing activities
|
|
(466,424
|
)
|
|
(2,670,998
|
)
|
|
(1,688,523
|
)
|
|||
Financing activities
|
|
(172,206
|
)
|
|
2,057,115
|
|
|
876,665
|
|
|||
Net increase (decrease) in cash and cash equivalents
|
|
$
|
30,979
|
|
|
$
|
(33,674
|
)
|
|
$
|
(319,253
|
)
|
•
|
$601.8 million
of capital expenditures,
net of
$0.5 million
of contributions in aid of construction costs from affiliates,
primarily related to the construction of Lancaster Train II (within the DJ Basin complex), plant construction at the DBM complex and expansion at the DBJV system;
|
•
|
$12.7 million
of cash paid for equipment purchases from Anadarko;
|
•
|
$11.4 million
of cash contributed to equity investments, primarily related to expansion projects at White Cliffs, TEP and FRP;
|
•
|
$3.5 million
of cash paid for post-closing purchase price adjustments related to the DBM acquisition;
|
•
|
$145.6 million
of net proceeds from the sale of the Dew and Pinnacle systems in East Texas; and
|
•
|
$16.2 million
of distributions from equity investments in excess of cumulative earnings.
|
•
|
$1.5 billion of cash paid for the acquisition of DBM, net of $30.6 million of cash acquired;
|
•
|
$722.3 million
of capital expenditures, net of
$0.2 million
of contributions in aid of construction costs from affiliates, primarily related to the construction of Lancaster Trains I and II, as well as compression expansion projects, all within the DJ Basin complex;
|
•
|
$356.3 million of cash paid for the acquisition of the TEFR Interests;
|
•
|
$42.0 million of cash paid related to the construction of the Front Range Pipeline, which was completed in March 2014;
|
•
|
$22.9 million
of cash paid for equipment purchases from Anadarko;
|
•
|
$10.5 million of cash paid for White Cliffs expansion projects;
|
•
|
$6.6 million of cash paid related to the construction of the Texas Express Pipeline, which was completed in November 2013; and
|
•
|
$18.1 million
of distributions from equity investments in excess of cumulative earnings.
|
•
|
$681.4 million
of capital expenditures, net of
$0.6 million
of contributions in aid of construction costs from affiliates;
|
•
|
$465.5 million of cash paid for the Non-Operated Marcellus Interest acquisition;
|
•
|
$236.9 million of capital contributions to TEG, TEP and FRP for construction costs;
|
•
|
$134.6 million of cash paid for the Anadarko-Operated Marcellus Interest acquisition;
|
•
|
$78.1 million of cash paid for the Mont Belvieu JV acquisition;
|
•
|
$38.7 million of capital contributions to the Mont Belvieu JV to fund our share of construction costs for the fractionation trains completed in the fourth quarter of 2013;
|
•
|
$27.5 million of cash paid for the OTTCO acquisition;
|
•
|
$19.1 million of cash paid for a White Cliffs expansion project;
|
•
|
$11.2 million
of cash paid for equipment purchases from Anadarko; and
|
•
|
$4.4 million
of distributions from equity investments in excess of cumulative earnings.
|
•
|
$610.0 million
of repayments of outstanding borrowings under our RCF;
|
•
|
$545.1 million
of distributions paid to our unitholders;
|
•
|
$12.2 million
of distributions paid to the noncontrolling interest owner of Chipeta;
|
•
|
$489.6 million of net proceeds from the 2025 Notes offering in June 2015, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of the outstanding borrowings under our RCF;
|
•
|
$400.0 million
of borrowings to fund capital expenditures and for general partnership purposes;
|
•
|
$57.4 million
of net proceeds from sales of common units under the $500.0 million COP (as discussed in
Registered Securities
within this
Item 7
). Net proceeds were used for general partnership purposes, including funding capital expenditures;
|
•
|
$31.5 million
of net contributions from Anadarko representing intercompany transactions attributable to the acquisition of DBJV; and
|
•
|
$18.4 million
of capital contribution from Anadarko related to the above-market component of swap extensions (see
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under
Part II
,
Item 8
of this Form
10-K
).
|
•
|
$750.0 million of proceeds from the issuance of Class C units to a subsidiary of Anadarko, all of which was used to fund a portion of the acquisition of DBM;
|
•
|
$603.0 million of net proceeds from our November 2014 equity offering, including net proceeds from a capital contribution by our general partner, part of which was used to fund a portion of the acquisition of DBM;
|
•
|
$475.0 million of borrowings to fund a portion of the acquisition of DBM;
|
•
|
$389.5 million of net proceeds from the 2044 Notes offering in March 2014, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of the outstanding borrowings under our RCF;
|
•
|
$350.0 million of borrowings to fund the acquisition of the TEFR Interests;
|
•
|
$335.0 million of borrowings to fund capital expenditures and general partnership purposes;
|
•
|
$100.0 million of net proceeds from the offering of additional 2018 Notes in March 2014, after underwriting discounts, original issue premium and offering costs, part of which was used to repay a portion of the outstanding borrowings under our RCF;
|
•
|
$83.2 million of net proceeds from sales of common units under the $125.0 million COP, including net proceeds from capital contributions by our general partner;
|
•
|
$27.8 million
of net contributions from Anadarko representing intercompany transactions attributable to the acquisitions of DBJV and the TEFR Interests;
|
•
|
$18.1 million of net proceeds related to the partial exercise of the underwriters’ over-allotment option granted in connection with our December 2013 equity offering;
|
•
|
$650.0 million of repayments of outstanding borrowings under our RCF;
|
•
|
$408.6 million
of distributions paid to our unitholders; and
|
•
|
$15.1 million
of distributions paid to the noncontrolling interest owner of Chipeta.
|
•
|
$424.7 million of net proceeds from our May 2013 equity offering, including net proceeds from a capital contribution by our general partner, $245.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;
|
•
|
$299.0 million of borrowings to fund capital expenditures;
|
•
|
$273.7 million of net proceeds from our December 2013 equity offering, including net proceeds from a capital contribution by our general partner, $215.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;
|
•
|
$250.0 million of borrowings to fund the Non-Operated Marcellus Interest acquisition;
|
•
|
$247.6 million of net proceeds from our 2018 Notes offering in August 2013, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of our outstanding borrowings under our RCF;
|
•
|
$200.1 million
of net contributions from Anadarko representing intercompany transactions attributable to the acquisitions of the TEFR Interests and the Non-Operated Marcellus Interest;
|
•
|
$133.5 million of borrowings to fund the Anadarko-Operated Marcellus Interest acquisition;
|
•
|
$41.8 million of net proceeds from sales of common units under the $125.0 million COP, including net proceeds from capital contributions by our general partner;
|
•
|
$27.5 million of borrowings to fund the OTTCO acquisition;
|
•
|
$2.2 million of contributions from the noncontrolling interest owners of Chipeta;
|
•
|
$710.0 million of repayments of outstanding borrowings under our RCF;
|
•
|
$299.1 million
of distributions paid to our unitholders; and
|
•
|
$13.1 million
of distributions paid to the noncontrolling interest owner of Chipeta.
|
|
|
Obligations by Period
|
||||||||||||||||||||||||||
thousands
|
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
Thereafter
|
|
Total
|
||||||||||||||
Long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Principal
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
350,000
|
|
|
$
|
300,000
|
|
|
$
|
—
|
|
|
$
|
2,070,000
|
|
|
$
|
2,720,000
|
|
Interest
|
|
108,052
|
|
|
108,052
|
|
|
104,604
|
|
|
95,948
|
|
|
95,225
|
|
|
657,898
|
|
|
1,169,779
|
|
|||||||
Asset retirement obligations
|
|
3,555
|
|
|
1,729
|
|
|
—
|
|
|
370
|
|
|
—
|
|
|
114,873
|
|
|
120,527
|
|
|||||||
Capital expenditures
|
|
45,045
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
45,045
|
|
|||||||
Credit facility fees
|
|
2,400
|
|
|
2,400
|
|
|
2,400
|
|
|
375
|
|
|
—
|
|
|
—
|
|
|
7,575
|
|
|||||||
Environmental obligations
|
|
1,136
|
|
|
708
|
|
|
333
|
|
|
278
|
|
|
123
|
|
|
—
|
|
|
2,578
|
|
|||||||
Operating leases
|
|
2,614
|
|
|
1,705
|
|
|
109
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,428
|
|
|||||||
Deferred purchase price obligation - Anadarko
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
282,807
|
|
|
—
|
|
|
282,807
|
|
|||||||
Total
|
|
$
|
162,802
|
|
|
$
|
114,594
|
|
|
$
|
457,446
|
|
|
$
|
396,971
|
|
|
$
|
378,155
|
|
|
$
|
2,842,771
|
|
|
$
|
4,352,739
|
|
•
|
significant changes in our unit price;
|
•
|
changes in commodity prices;
|
•
|
changes in operating and capital costs;
|
•
|
impairments recognized;
|
•
|
acquisitions and disposals of assets;
|
•
|
changes in throughput; and
|
•
|
changes in trading multiples for our peers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Donald R. Sinclair
|
|
Donald R. Sinclair
President and Chief Executive Officer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
|
/s/ Benjamin M. Fink
|
|
Benjamin M. Fink
Senior Vice President, Chief Financial Officer and Treasurer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands except per-unit amounts
|
|
2015
|
|
2014
(1)
|
|
2013
(1)
|
||||||
Revenues and other – affiliates
|
|
|
|
|
|
|
||||||
Gathering, processing and transportation of natural gas and natural gas liquids
|
|
$
|
581,644
|
|
|
$
|
467,540
|
|
|
$
|
340,116
|
|
Natural gas, natural gas liquids and drip condensate sales
|
|
447,106
|
|
|
581,317
|
|
|
502,219
|
|
|||
Other
|
|
1,172
|
|
|
5,078
|
|
|
1,868
|
|
|||
Total revenues and other – affiliates
|
|
1,029,922
|
|
|
1,053,935
|
|
|
844,203
|
|
|||
Revenues and other – third parties
|
|
|
|
|
|
|
||||||
Gathering, processing and transportation of natural gas and natural gas liquids
|
|
356,477
|
|
|
277,605
|
|
|
190,877
|
|
|||
Natural gas, natural gas liquids and drip condensate sales
|
|
170,843
|
|
|
42,916
|
|
|
46,289
|
|
|||
Other
|
|
4,130
|
|
|
8,412
|
|
|
4,113
|
|
|||
Total revenues and other – third parties
|
|
531,450
|
|
|
328,933
|
|
|
241,279
|
|
|||
Total revenues and other
|
|
1,561,372
|
|
|
1,382,868
|
|
|
1,085,482
|
|
|||
Equity income, net
(2)
|
|
71,251
|
|
|
57,836
|
|
|
22,948
|
|
|||
Operating expenses
|
|
|
|
|
|
|
||||||
Cost of product
(3)
|
|
528,435
|
|
|
454,445
|
|
|
373,171
|
|
|||
Operation and maintenance
(3)
|
|
296,774
|
|
|
255,844
|
|
|
201,759
|
|
|||
General and administrative
(3)
|
|
38,108
|
|
|
36,223
|
|
|
31,353
|
|
|||
Property and other taxes
|
|
30,533
|
|
|
26,066
|
|
|
23,806
|
|
|||
Depreciation and amortization
|
|
244,163
|
|
|
186,514
|
|
|
149,815
|
|
|||
Impairments
|
|
514,096
|
|
|
3,084
|
|
|
1,267
|
|
|||
Total operating expenses
|
|
1,652,109
|
|
|
962,176
|
|
|
781,171
|
|
|||
Gain on divestiture and other, net
(4)
|
|
57,020
|
|
|
—
|
|
|
—
|
|
|||
Operating income (loss)
|
|
37,534
|
|
|
478,528
|
|
|
327,259
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
(5)
|
|
(113,872
|
)
|
|
(76,766
|
)
|
|
(51,797
|
)
|
|||
Other income (expense), net
|
|
(619
|
)
|
|
864
|
|
|
1,837
|
|
|||
Income (loss) before income taxes
|
|
(60,057
|
)
|
|
419,526
|
|
|
294,199
|
|
|||
Income tax (benefit) expense
|
|
3,380
|
|
|
11,659
|
|
|
4,660
|
|
|||
Net income (loss)
|
|
(63,437
|
)
|
|
407,867
|
|
|
289,539
|
|
|||
Net income attributable to noncontrolling interest
|
|
10,101
|
|
|
14,025
|
|
|
10,816
|
|
|||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
(73,538
|
)
|
|
$
|
393,842
|
|
|
$
|
278,723
|
|
Limited partners’ interest in net income (loss):
|
|
|
|
|
|
|
||||||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
(73,538
|
)
|
|
$
|
393,842
|
|
|
$
|
278,723
|
|
Pre-acquisition net (income) loss allocated to Anadarko
|
|
(1,742
|
)
|
|
(16,353
|
)
|
|
(8,224
|
)
|
|||
General partner interest in net (income) loss
(6)
|
|
(180,996
|
)
|
|
(120,980
|
)
|
|
(69,633
|
)
|
|||
Limited partners’ interest in net income (loss)
(6)
|
|
(256,276
|
)
|
|
256,509
|
|
|
200,866
|
|
|||
Net income (loss) per common unit – basic
(7)
|
|
$
|
(1.95
|
)
|
|
$
|
2.13
|
|
|
$
|
1.83
|
|
Net income (loss) per common unit – diluted
(7)
|
|
(1.95
|
)
|
|
2.12
|
|
|
1.83
|
|
(1)
|
Financial information has been recast to include the financial position and results attributable to the DBJV system. See
Note 1
and
Note 2
.
|
(2)
|
Income earned from equity investments is classified as affiliate. See
Note 1
.
|
(3)
|
Cost of product includes product purchases from Anadarko (as defined in
Note 1
) of
$167.4 million
,
$127.9 million
and
$136.6 million
for the
years ended December 31, 2015
,
2014
and
2013
, respectively. Operation and maintenance includes charges from Anadarko of
$67.1 million
,
$62.3 million
and
$59.7 million
for the
years ended December 31, 2015
,
2014
and
2013
, respectively. General and administrative includes charges from Anadarko of
$30.7 million
,
$29.0 million
and
$25.0 million
for the
years ended December 31, 2015
,
2014
and
2013
, respectively. See
Note 5
.
|
(4)
|
Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See
Note 1
.
|
(5)
|
Includes affiliate (as defined in
Note 1
) interest expense of
$14.4 million
for the
year ended December 31, 2015
, and
zero
for each of the
years ended December 31, 2014
and
2013
. See
Note 2
and
Note 12
.
|
(6)
|
Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets (as defined in
Note 1
). See
Note 4
.
|
(7)
|
See
Note 4
for the calculation of net income (loss) per common unit.
|
|
|
December 31,
|
||||||
thousands except number of units
|
|
2015
|
|
2014
(1)
|
||||
ASSETS
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
98,033
|
|
|
$
|
67,054
|
|
Accounts receivable, net
(2)
|
|
180,993
|
|
|
109,243
|
|
||
Other current assets
(3)
|
|
7,855
|
|
|
10,053
|
|
||
Total current assets
|
|
286,881
|
|
|
186,350
|
|
||
Note receivable – Anadarko
|
|
260,000
|
|
|
260,000
|
|
||
Property, plant and equipment
|
|
|
|
|
||||
Cost
|
|
5,904,637
|
|
|
5,626,650
|
|
||
Less accumulated depreciation
|
|
1,614,663
|
|
|
1,055,207
|
|
||
Net property, plant and equipment
|
|
4,289,974
|
|
|
4,571,443
|
|
||
Goodwill
|
|
389,686
|
|
|
389,087
|
|
||
Other intangible assets
|
|
832,127
|
|
|
884,857
|
|
||
Equity investments
|
|
618,887
|
|
|
634,492
|
|
||
Other assets
|
|
29,707
|
|
|
28,289
|
|
||
Total assets
|
|
$
|
6,707,262
|
|
|
$
|
6,954,518
|
|
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accounts and imbalance payables
(4)
|
|
$
|
64,606
|
|
|
$
|
54,232
|
|
Accrued ad valorem taxes
|
|
17,808
|
|
|
14,812
|
|
||
Accrued liabilities
|
|
116,818
|
|
|
170,789
|
|
||
Total current liabilities
|
|
199,232
|
|
|
239,833
|
|
||
Long-term debt
|
|
2,707,357
|
|
|
2,422,954
|
|
||
Deferred income taxes
|
|
5,963
|
|
|
45,642
|
|
||
Asset retirement obligations and other
|
|
118,606
|
|
|
111,714
|
|
||
Deferred purchase price obligation – Anadarko
(5)
|
|
188,674
|
|
|
—
|
|
||
Total long-term liabilities
|
|
3,020,600
|
|
|
2,580,310
|
|
||
Total liabilities
|
|
3,219,832
|
|
|
2,820,143
|
|
||
Equity and partners’ capital
|
|
|
|
|
||||
Common units (128,576,965 and 127,695,130 units issued and outstanding at December 31, 2015 and 2014, respectively)
|
|
2,588,991
|
|
|
3,119,714
|
|
||
Class C units (11,411,862 and 10,913,853 units issued and outstanding at December 31, 2015 and 2014, respectively)
|
|
710,891
|
|
|
716,957
|
|
||
General partner units (2,583,068 units issued and outstanding at December 31, 2015 and 2014)
|
|
120,164
|
|
|
105,725
|
|
||
Net investment by Anadarko
|
|
—
|
|
|
122,509
|
|
||
Total partners’ capital
|
|
3,420,046
|
|
|
4,064,905
|
|
||
Noncontrolling interest
|
|
67,384
|
|
|
69,470
|
|
||
Total equity and partners’ capital
|
|
3,487,430
|
|
|
4,134,375
|
|
||
Total liabilities, equity and partners’ capital
|
|
$
|
6,707,262
|
|
|
$
|
6,954,518
|
|
(1)
|
Financial information has been recast to include the financial position and results attributable to the DBJV system. See
Note 1
and
Note 2
.
|
(2)
|
Accounts receivable, net includes amounts receivable from affiliates (as defined in
Note 1
) of
$42.7 million
and
$64.7 million
as of
December 31, 2015
and
2014
, respectively. Accounts receivable, net as of December 31, 2015, also includes an insurance claim receivable related to an incident at the DBM complex. See
Note 1
.
|
(3)
|
Other current assets includes imbalance receivables from affiliates of
zero
and
$0.2 million
as of
December 31, 2015
and
2014
, respectively.
|
(4)
|
Accounts and imbalance payables includes amounts payable to affiliates of
zero
and
$0.1 million
as of
December 31, 2015
and
2014
, respectively.
|
(5)
|
See
Note 2
.
|
|
|
Partners’ Capital
|
|
|
|
|
||||||||||||||||||
thousands
|
|
Net
Investment
by Anadarko
|
|
Common
Units
|
|
Class C
Units
|
|
General
Partner
Units
|
|
Noncontrolling
Interest
|
|
Total
|
||||||||||||
Balance at December 31, 2012
(1)
|
|
$
|
419,544
|
|
|
$
|
1,957,066
|
|
|
$
|
—
|
|
|
$
|
52,752
|
|
|
$
|
70,658
|
|
|
$
|
2,500,020
|
|
Net income (loss)
|
|
8,224
|
|
|
200,866
|
|
|
—
|
|
|
69,633
|
|
|
10,816
|
|
|
289,539
|
|
||||||
Issuance of common and general partner units, net of offering expenses
|
|
—
|
|
|
724,811
|
|
|
—
|
|
|
15,775
|
|
|
—
|
|
|
740,586
|
|
||||||
Contributions from noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,247
|
|
|
2,247
|
|
||||||
Distributions to noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13,127
|
)
|
|
(13,127
|
)
|
||||||
Distributions to unitholders
|
|
—
|
|
|
(239,157
|
)
|
|
—
|
|
|
(59,944
|
)
|
|
—
|
|
|
(299,101
|
)
|
||||||
Acquisitions from affiliates
|
|
(255,635
|
)
|
|
(209,865
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(465,500
|
)
|
||||||
Contributions of equity-based compensation from Anadarko
(2)
|
|
—
|
|
|
2,865
|
|
|
—
|
|
|
58
|
|
|
—
|
|
|
2,923
|
|
||||||
Net pre-acquisition contributions from (distributions to) Anadarko
(3)
|
|
194,592
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
194,592
|
|
||||||
Net distributions to Anadarko of other assets
|
|
—
|
|
|
(5,738
|
)
|
|
—
|
|
|
(117
|
)
|
|
—
|
|
|
(5,855
|
)
|
||||||
Elimination of net deferred tax liabilities
|
|
46,530
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46,530
|
|
||||||
Other
|
|
—
|
|
|
345
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
345
|
|
||||||
Balance at December 31, 2013
(1)
|
|
$
|
413,255
|
|
|
$
|
2,431,193
|
|
|
$
|
—
|
|
|
$
|
78,157
|
|
|
$
|
70,594
|
|
|
$
|
2,993,199
|
|
Net income (loss)
|
|
16,353
|
|
|
254,737
|
|
|
1,772
|
|
|
120,980
|
|
|
14,025
|
|
|
407,867
|
|
||||||
Issuance of common and general partner units, net of offering expenses
|
|
—
|
|
|
691,417
|
|
|
—
|
|
|
13,311
|
|
|
—
|
|
|
704,728
|
|
||||||
Issuance of Class C units
|
|
—
|
|
|
—
|
|
|
750,000
|
|
|
—
|
|
|
—
|
|
|
750,000
|
|
||||||
Beneficial conversion feature of Class C units
|
|
—
|
|
|
34,815
|
|
|
(34,815
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Distributions to noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15,149
|
)
|
|
(15,149
|
)
|
||||||
Distributions to unitholders
|
|
—
|
|
|
(302,049
|
)
|
|
—
|
|
|
(106,572
|
)
|
|
—
|
|
|
(408,621
|
)
|
||||||
Acquisitions from affiliates
|
|
(372,784
|
)
|
|
16,534
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(356,250
|
)
|
||||||
Contributions of equity-based compensation from Anadarko
(2)
|
|
—
|
|
|
3,104
|
|
|
—
|
|
|
63
|
|
|
—
|
|
|
3,167
|
|
||||||
Net pre-acquisition contributions from (distributions to) Anadarko
(3)
|
|
27,525
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
27,525
|
|
||||||
Net distributions to Anadarko of other assets
|
|
—
|
|
|
(10,519
|
)
|
|
—
|
|
|
(214
|
)
|
|
—
|
|
|
(10,733
|
)
|
||||||
Elimination of net deferred tax liabilities
|
|
38,160
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
38,160
|
|
||||||
Other
|
|
—
|
|
|
482
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
482
|
|
||||||
Balance at December 31, 2014
(1)
|
|
$
|
122,509
|
|
|
$
|
3,119,714
|
|
|
$
|
716,957
|
|
|
$
|
105,725
|
|
|
$
|
69,470
|
|
|
$
|
4,134,375
|
|
Net income (loss)
|
|
1,742
|
|
|
(238,166
|
)
|
|
(18,110
|
)
|
|
180,996
|
|
|
10,101
|
|
|
(63,437
|
)
|
||||||
Above-market component of swap extensions with Anadarko
(4)
|
|
—
|
|
|
18,449
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
18,449
|
|
||||||
Issuance of common units, net of offering expenses
|
|
—
|
|
|
57,353
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
57,353
|
|
||||||
Amortization of beneficial conversion feature of Class C units
|
|
—
|
|
|
(12,044
|
)
|
|
12,044
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Distributions to noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12,187
|
)
|
|
(12,187
|
)
|
||||||
Distributions to unitholders
|
|
—
|
|
|
(378,602
|
)
|
|
—
|
|
|
(166,541
|
)
|
|
—
|
|
|
(545,143
|
)
|
||||||
Acquisitions from affiliates
|
|
(197,562
|
)
|
|
23,286
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(174,276
|
)
|
||||||
Contributions of equity-based compensation from Anadarko
(2)
|
|
—
|
|
|
3,480
|
|
|
—
|
|
|
71
|
|
|
—
|
|
|
3,551
|
|
||||||
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
31,467
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31,467
|
|
||||||
Net distributions to Anadarko of other assets
|
|
—
|
|
|
(4,680
|
)
|
|
—
|
|
|
(87
|
)
|
|
—
|
|
|
(4,767
|
)
|
||||||
Elimination of net deferred tax liabilities
|
|
41,844
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
41,844
|
|
||||||
Other
|
|
—
|
|
|
201
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
201
|
|
||||||
Balance at December 31, 2015
|
|
$
|
—
|
|
|
$
|
2,588,991
|
|
|
$
|
710,891
|
|
|
$
|
120,164
|
|
|
$
|
67,384
|
|
|
$
|
3,487,430
|
|
(1)
|
Financial information has been recast to include the financial position and results attributable to the DBJV system. See
Note 1
and
Note 2
.
|
(2)
|
Associated with the Anadarko Incentive Plans as defined and described in
Note 1
and
Note 5
.
|
(3)
|
Includes deferred taxes on capitalized interest of
$0.3 million
and
$5.5 million
associated with the acquisition of the TEFR Interests (as defined and described in
Note 1
) for the years ended December 31, 2014 and 2013, respectively.
|
(4)
|
See
Note 5
.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2015
|
|
2014
(1)
|
|
2013
(1)
|
||||||
Cash flows from operating activities
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
(63,437
|
)
|
|
$
|
407,867
|
|
|
$
|
289,539
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
Depreciation and amortization
|
|
244,163
|
|
|
186,514
|
|
|
149,815
|
|
|||
Impairments
|
|
514,096
|
|
|
3,084
|
|
|
1,267
|
|
|||
Non-cash equity-based compensation expense
|
|
4,188
|
|
|
3,920
|
|
|
3,521
|
|
|||
Deferred income taxes
|
|
1,932
|
|
|
13,325
|
|
|
40,035
|
|
|||
Accretion and amortization of long-term obligations, net
|
|
17,698
|
|
|
2,736
|
|
|
2,449
|
|
|||
Equity income, net
(2)
|
|
(71,251
|
)
|
|
(57,836
|
)
|
|
(22,948
|
)
|
|||
Distributions from equity investment earnings
(2)
|
|
82,054
|
|
|
62,967
|
|
|
17,698
|
|
|||
Gain on divestiture and other, net
(3)
|
|
(57,020
|
)
|
|
—
|
|
|
—
|
|
|||
Lower of cost or market inventory adjustments
|
|
443
|
|
|
—
|
|
|
—
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
|
||||||
(Increase) decrease in accounts receivable, net
|
|
(5,614
|
)
|
|
(6,691
|
)
|
|
(13,936
|
)
|
|||
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net
|
|
3,154
|
|
|
(39,162
|
)
|
|
28,867
|
|
|||
Change in other items, net
|
|
(797
|
)
|
|
3,485
|
|
|
(3,702
|
)
|
|||
Net cash provided by operating activities
|
|
669,609
|
|
|
580,209
|
|
|
492,605
|
|
|||
Cash flows from investing activities
|
|
|
|
|
|
|
||||||
Capital expenditures
|
|
(602,289
|
)
|
|
(722,443
|
)
|
|
(681,999
|
)
|
|||
Contributions in aid of construction costs from affiliates
|
|
461
|
|
|
183
|
|
|
617
|
|
|||
Acquisitions from affiliates
|
|
(12,664
|
)
|
|
(379,193
|
)
|
|
(476,711
|
)
|
|||
Acquisitions from third parties
|
|
(3,514
|
)
|
|
(1,523,327
|
)
|
|
(240,274
|
)
|
|||
Investments in equity affiliates
|
|
(11,442
|
)
|
|
(64,278
|
)
|
|
(294,693
|
)
|
|||
Distributions from equity investments in excess of cumulative earnings
(2)
|
|
16,244
|
|
|
18,055
|
|
|
4,438
|
|
|||
Proceeds from the sale of assets to affiliates
|
|
925
|
|
|
—
|
|
|
85
|
|
|||
Proceeds from the sale of assets to third parties
|
|
145,855
|
|
|
5
|
|
|
14
|
|
|||
Net cash used in investing activities
|
|
(466,424
|
)
|
|
(2,670,998
|
)
|
|
(1,688,523
|
)
|
|||
Cash flows from financing activities
|
|
|
|
|
|
|
||||||
Borrowings, net of debt issuance costs
|
|
889,606
|
|
|
1,646,878
|
|
|
957,503
|
|
|||
Repayments of debt
|
|
(610,000
|
)
|
|
(650,000
|
)
|
|
(710,000
|
)
|
|||
Increase (decrease) in outstanding checks
|
|
(1,751
|
)
|
|
1,693
|
|
|
(1,763
|
)
|
|||
Proceeds from the issuance of common and general partner units, net of offering expenses
|
|
57,353
|
|
|
704,489
|
|
|
740,825
|
|
|||
Proceeds from the issuance of Class C units
|
|
—
|
|
|
750,000
|
|
|
—
|
|
|||
Distributions to unitholders
(4)
|
|
(545,143
|
)
|
|
(408,621
|
)
|
|
(299,101
|
)
|
|||
Contributions from noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
2,247
|
|
|||
Distributions to noncontrolling interest owner
|
|
(12,187
|
)
|
|
(15,149
|
)
|
|
(13,127
|
)
|
|||
Net contributions from Anadarko
|
|
31,467
|
|
|
27,825
|
|
|
200,081
|
|
|||
Above-market component of swap extensions with Anadarko
(4)
|
|
18,449
|
|
|
—
|
|
|
—
|
|
|||
Net cash provided by (used in) financing activities
|
|
(172,206
|
)
|
|
2,057,115
|
|
|
876,665
|
|
|||
Net increase (decrease) in cash and cash equivalents
|
|
30,979
|
|
|
(33,674
|
)
|
|
(319,253
|
)
|
|||
Cash and cash equivalents at beginning of period
|
|
67,054
|
|
|
100,728
|
|
|
419,981
|
|
|||
Cash and cash equivalents at end of period
|
|
$
|
98,033
|
|
|
$
|
67,054
|
|
|
$
|
100,728
|
|
Supplemental disclosures
|
|
|
|
|
|
|
||||||
Acquisition of DBJV from Anadarko
|
|
$
|
174,276
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Net distributions to (contributions from) Anadarko of other assets
|
|
4,767
|
|
|
10,733
|
|
|
5,855
|
|
|||
Interest paid, net of capitalized interest
|
|
94,720
|
|
|
67,648
|
|
|
47,098
|
|
|||
Taxes paid (reimbursements received)
|
|
—
|
|
|
(90
|
)
|
|
552
|
|
|||
Capital lease asset transfer
(5)
|
|
—
|
|
|
4,833
|
|
|
—
|
|
(1)
|
Financial information has been recast to include the financial position and results attributable to the DBJV system. See
Note 1
and
Note 2
.
|
(2)
|
Income earned on, distributions from and contributions to equity investments are classified as affiliate. See
Note 1
.
|
(3)
|
Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See
Note 1
.
|
(4)
|
See
Note 5
.
|
(5)
|
For the
year ended December 31, 2014
, represents transfers of
$4.6 million
from other long-term assets associated with the capital lease component of a processing agreement. See
Note 7
.
|
|
|
Owned and
Operated
|
|
Operated
Interests
|
|
Non-Operated
Interests
|
|
Equity
Interests
|
||||
Natural gas gathering systems
|
|
12
|
|
|
2
|
|
|
5
|
|
|
2
|
|
Natural gas treating facilities
|
|
12
|
|
|
4
|
|
|
—
|
|
|
3
|
|
Natural gas processing plants/trains
(1)
|
|
18
|
|
|
5
|
|
|
—
|
|
|
2
|
|
NGL pipelines
|
|
2
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Natural gas pipelines
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Oil pipeline
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
(1)
|
On December 3, 2015, an incident occurred at the DBM complex. See
Note 7
.
|
thousands except unit and percent amounts
|
|
Acquisition
Date
|
|
Percentage
Acquired |
|
Deferred Purchase Price
Obligation - Anadarko
|
|
Borrowings
|
|
Cash
On Hand
|
|
Common Units
Issued to Anadarko
|
|
Class C Units
Issued to Anadarko
|
|||||||||
Non-Operated Marcellus Interest
(1)
|
|
03/01/2013
|
|
33.75
|
%
|
|
$
|
—
|
|
|
$
|
250,000
|
|
|
$
|
215,500
|
|
|
449,129
|
|
|
—
|
|
Anadarko-Operated Marcellus Interest
(2)
|
|
03/08/2013
|
|
33.75
|
%
|
|
—
|
|
|
133,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Mont Belvieu JV
(3)
|
|
06/05/2013
|
|
25
|
%
|
|
—
|
|
|
—
|
|
|
78,129
|
|
|
—
|
|
|
—
|
|
|||
OTTCO
(4)
|
|
09/03/2013
|
|
100
|
%
|
|
—
|
|
|
27,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
TEFR Interests
(5)
|
|
03/03/2014
|
|
Various
(5)
|
|
|
—
|
|
|
350,000
|
|
|
6,250
|
|
|
308,490
|
|
|
—
|
|
|||
DBM
(6)
|
|
11/25/2014
|
|
100
|
%
|
|
—
|
|
|
475,000
|
|
|
298,327
|
|
|
—
|
|
|
10,913,853
|
|
|||
DBJV system
(7)
|
|
03/02/2015
|
|
50
|
%
|
|
174,276
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
The Partnership acquired Anadarko’s 33.75% interest (non-operated) (the “Non-Operated Marcellus Interest”) in the Liberty and Rome gas gathering systems (the “Non-Operated Marcellus Interest systems”), serving production from the Marcellus shale in North-central Pennsylvania. In connection with the issuance of the common units, the Partnership’s general partner purchased
9,166
general partner units for consideration of
$0.5 million
.
|
(2)
|
The Partnership acquired a 33.75% interest (the “Anadarko-Operated Marcellus Interest”) in each of the Larry’s Creek, Seely and Warrensville gas gathering systems (the “Anadarko-Operated Marcellus Interest systems”), which are operated by Anadarko and serve production from the Marcellus shale in North-central Pennsylvania, from a third party. During the third quarter of 2013, the Partnership recorded a
$1.1 million
decrease in the assets acquired and liabilities assumed in the acquisition, representing the final purchase price allocation.
|
(3)
|
The Partnership acquired a
25%
interest in the Mont Belvieu JV, an entity formed to design, construct, and own
two
fractionation trains located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting.
|
(4)
|
The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming.
|
(5)
|
The Partnership acquired a
20%
interest in each of TEG and TEP and a
33.33%
interest in FRP from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and Denver-Julesburg (“DJ”) Basins. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, the Partnership issued
6,296
general partner units to the general partner in exchange for the general partner’s proportionate capital contribution of
$0.4 million
.
|
(6)
|
The Partnership acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, the Partnership changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which are collectively referred to as the “DBM complex” and serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. See
DBM acquisition
below for further information, including the final allocation of the purchase price.
|
(7)
|
The Partnership acquired Anadarko’s interest in Delaware Basin JV Gathering LLC (“DBJV”), which owns a
50%
interest in a gathering system and related facilities (the “DBJV system”). The DBJV system is located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. The Partnership will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. The Partnership currently estimates the future payment will be
$282.8 million
, the net present value of which was
$174.3 million
as of the acquisition date. See
DBJV acquisition—Deferred purchase price obligation - Anadarko
below.
|
|
|
Year Ended December 31, 2014
|
||||||||||
thousands
|
|
Partnership Historical
(1)
|
|
DBJV System
|
|
Combined
|
||||||
Revenues and other
|
|
$
|
1,320,756
|
|
|
$
|
62,112
|
|
|
$
|
1,382,868
|
|
Equity income, net
|
|
57,836
|
|
|
—
|
|
|
57,836
|
|
|||
Net income (loss)
|
|
390,558
|
|
|
17,309
|
|
|
407,867
|
|
|||
|
|
|
|
|
|
|
||||||
|
|
Year Ended December 31, 2013
|
||||||||||
thousands
|
|
Partnership Historical
(1)
|
|
DBJV System
|
|
Combined
|
||||||
Revenues and other
|
|
$
|
1,052,937
|
|
|
$
|
32,545
|
|
|
$
|
1,085,482
|
|
Equity income, net
|
|
22,948
|
|
|
—
|
|
|
22,948
|
|
|||
Net income (loss)
|
|
285,443
|
|
|
4,096
|
|
|
289,539
|
|
(1)
|
See
Adjustments to previously issued financial statements
in
Note 1
.
|
thousands
|
|
|
||
Current assets
|
|
$
|
60,888
|
|
Property, plant and equipment
|
|
467,171
|
|
|
Goodwill
|
|
284,749
|
|
|
Other intangible assets
|
|
811,048
|
|
|
Accounts payables
|
|
(18,621
|
)
|
|
Accrued liabilities
|
|
(37,360
|
)
|
|
Deferred income taxes
|
|
(1,342
|
)
|
|
Asset retirement obligations and other
|
|
(9,060
|
)
|
|
Total purchase price
|
|
$
|
1,557,473
|
|
|
|
Year Ended December 31,
|
||||||
thousands except per-unit amounts
|
|
2014
|
|
2013
|
||||
Revenues and other
|
|
$
|
1,506,135
|
|
|
$
|
1,162,749
|
|
Net income (loss)
|
|
349,729
|
|
|
243,478
|
|
||
Net income (loss) attributable to Western Gas Partners, LP
|
|
335,704
|
|
|
232,622
|
|
||
Net income (loss) per common unit – basic and diluted
|
|
1.34
|
|
|
1.12
|
|
thousands except per-unit amounts
Quarters Ended
|
|
Total Quarterly
Distribution
per Unit
|
|
Total Quarterly
Cash Distribution
|
|
Date of
Distribution
|
|||||
2013
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.540
|
|
|
$
|
70,143
|
|
|
May 2013
|
|
June 30
|
|
0.560
|
|
|
79,315
|
|
|
August 2013
|
|||
September 30
|
|
0.580
|
|
|
83,986
|
|
|
November 2013
|
|||
December 31
|
|
0.600
|
|
|
92,609
|
|
|
February 2014
|
|||
2014
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.625
|
|
|
$
|
98,749
|
|
|
May 2014
|
|
June 30
|
|
0.650
|
|
|
105,655
|
|
|
August 2014
|
|||
September 30
|
|
0.675
|
|
|
111,608
|
|
|
November 2014
|
|||
December 31
|
|
0.700
|
|
|
126,044
|
|
|
February 2015
|
|||
2015
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.725
|
|
|
$
|
133,203
|
|
|
May 2015
|
|
June 30
|
|
0.750
|
|
|
139,736
|
|
|
August 2015
|
|||
September 30
|
|
0.775
|
|
|
146,160
|
|
|
November 2015
|
|||
December 31
(1)
|
|
0.800
|
|
|
152,588
|
|
|
February 2016
|
(1)
|
On
January 21, 2016
, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of
$0.800
per unit, or
$152.6 million
in aggregate, including incentive distributions, but excluding distributions on Class C units (see
Class C unit distributions
below). The cash distribution was paid on
February 11, 2016
, to unitholders of record at the close of business on
February 1, 2016
.
|
thousands except unit amounts
For the Quarters Ended
|
|
PIK Class C
Units
|
|
Implied
Fair Value
|
|
Date of
Distribution |
|||
2014
|
|
|
|
|
|
|
|||
December 31
(1)
|
|
45,711
|
|
|
$
|
3,072
|
|
|
February 2015
|
2015
|
|
|
|
|
|
|
|||
March 31
|
|
118,230
|
|
|
$
|
8,101
|
|
|
May 2015
|
June 30
|
|
153,020
|
|
|
8,721
|
|
|
August 2015
|
|
September 30
|
|
181,048
|
|
|
9,724
|
|
|
November 2015
|
|
December 31
|
|
323,584
|
|
|
10,070
|
|
|
February 2016
|
(1)
|
Prorated for the
37
-day period the Class C units were outstanding during the fourth quarter of 2014.
|
thousands except unit and per-unit amounts
|
|
Common Units
Issued
|
|
GP Units
Issued
(1)
|
|
Price Per
Unit
|
|
Underwriting
Discount and
Other Offering
Expenses
|
|
Net
Proceeds
|
||||||||
2013
|
|
|
|
|
|
|
|
|
|
|
||||||||
May 2013 equity offering
(2)
|
|
7,015,000
|
|
|
143,163
|
|
|
$
|
61.18
|
|
|
$
|
13,203
|
|
|
$
|
424,733
|
|
December 2013 equity offering
(3)
|
|
4,800,000
|
|
|
97,959
|
|
|
61.51
|
|
|
9,447
|
|
|
291,827
|
|
|||
$125.0 million COP
(4)
|
|
685,735
|
|
|
13,996
|
|
|
60.84
|
|
|
965
|
|
|
41,603
|
|
|||
2014
|
|
|
|
|
|
|
|
|
|
|
||||||||
$125.0 million COP
(5)
|
|
1,133,384
|
|
|
23,132
|
|
|
$
|
73.48
|
|
|
$
|
1,738
|
|
|
$
|
83,245
|
|
November 2014 equity offering
(6)
|
|
8,620,153
|
|
|
153,061
|
|
|
70.85
|
|
|
18,615
|
|
|
602,967
|
|
|||
2015
|
|
|
|
|
|
|
|
|
|
|
||||||||
$500.0 million COP
(7)
|
|
873,525
|
|
|
—
|
|
|
$
|
66.61
|
|
|
$
|
805
|
|
|
$
|
57,385
|
|
(1)
|
Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution.
|
(2)
|
Includes the issuance of
915,000
common units pursuant to the full exercise of the underwriters’ over-allotment option.
|
(3)
|
Includes the issuance of
300,000
common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise (including the general partner’s proportionate capital contribution) were
$18.1 million
.
|
(4)
|
Represents common and general partner units issued during the year ended December 31, 2013, pursuant to the Partnership’s registration statement filed with the SEC in August 2012 authorizing the issuance of up to an aggregate of
$125.0 million
of common units (the “$125.0 million COP”). Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2013, were
$42.6 million
. The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2013.
|
(5)
|
Represents common and general partner units issued during the year ended December 31, 2014, under the $125.0 million COP. Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2014, were
$85.0 million
. The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2014. As of December 31, 2014, the Partnership had used all the capacity to issue common units under this registration statement.
|
(6)
|
Includes the issuance of
1,120,153
common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were
$77.0 million
. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its
2.0%
interest in the Partnership.
|
(7)
|
Represents common units issued during the year ended December 31, 2015, pursuant to the Partnership’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of
$500.0 million
of common units (the “$500.0 million COP”). Gross proceeds generated during the three months and year ended December 31, 2015, were
zero
and
$58.2 million
, respectively. Commissions paid during the three months and year ended December 31, 2015, were
zero
and
$0.6 million
, respectively. The price per unit in the table above represents an average price for all issuances under the $500.0 million COP during the year ended December 31, 2015.
|
|
|
Common
Units
|
|
Class C
Units
|
|
General
Partner Units
|
|
Total
|
||||
Balance at December 31, 2013
|
|
117,322,812
|
|
|
—
|
|
|
2,394,345
|
|
|
119,717,157
|
|
December 2013 equity offering
|
|
300,000
|
|
|
—
|
|
|
6,122
|
|
|
306,122
|
|
WES LTIP award vestings
|
|
10,291
|
|
|
—
|
|
|
112
|
|
|
10,403
|
|
TEFR Interests acquisition
|
|
308,490
|
|
|
—
|
|
|
6,296
|
|
|
314,786
|
|
$125.0 million COP
|
|
1,133,384
|
|
|
—
|
|
|
23,132
|
|
|
1,156,516
|
|
November 2014 equity offering
|
|
8,620,153
|
|
|
—
|
|
|
153,061
|
|
|
8,773,214
|
|
Class C unit issuance
|
|
—
|
|
|
10,913,853
|
|
|
—
|
|
|
10,913,853
|
|
Balance at December 31, 2014
|
|
127,695,130
|
|
|
10,913,853
|
|
|
2,583,068
|
|
|
141,192,051
|
|
PIK Class C units
|
|
—
|
|
|
498,009
|
|
|
—
|
|
|
498,009
|
|
WES LTIP award vestings
|
|
8,310
|
|
|
—
|
|
|
—
|
|
|
8,310
|
|
$500.0 million COP
|
|
873,525
|
|
|
—
|
|
|
—
|
|
|
873,525
|
|
Balance at December 31, 2015
|
|
128,576,965
|
|
|
11,411,862
|
|
|
2,583,068
|
|
|
142,571,895
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands except per-unit amounts
|
|
2015
|
|
2014
|
|
2013
|
||||||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
(73,538
|
)
|
|
$
|
393,842
|
|
|
$
|
278,723
|
|
Pre-acquisition net (income) loss allocated to Anadarko
|
|
(1,742
|
)
|
|
(16,353
|
)
|
|
(8,224
|
)
|
|||
General partner interest in net (income) loss
|
|
(180,996
|
)
|
|
(120,980
|
)
|
|
(69,633
|
)
|
|||
Limited partners’ interest in net income (loss)
|
|
(256,276
|
)
|
|
256,509
|
|
|
200,866
|
|
|||
Net income (loss) allocable to common units
(1)
|
|
(250,210
|
)
|
|
254,737
|
|
|
200,866
|
|
|||
Net income (loss) allocable to Class C units
(1)
|
|
(6,066
|
)
|
|
1,772
|
|
|
—
|
|
|||
Limited partners’ interest in net income (loss)
|
|
$
|
(256,276
|
)
|
|
$
|
256,509
|
|
|
$
|
200,866
|
|
Net income (loss) per unit
|
|
|
|
|
|
|
||||||
Common units - basic
|
|
$
|
(1.95
|
)
|
|
$
|
2.13
|
|
|
$
|
1.83
|
|
Common units – diluted
(2)
|
|
(1.95
|
)
|
|
2.12
|
|
|
1.83
|
|
|||
Weighted-average units outstanding
|
|
|
|
|
|
|
||||||
Common units – basic
|
|
128,345
|
|
|
119,822
|
|
|
109,872
|
|
|||
Class C units
(2)
|
|
11,114
|
|
|
1,106
|
|
|
—
|
|
|||
Common units – diluted
|
|
139,459
|
|
|
120,928
|
|
|
109,872
|
|
(1)
|
Adjusted to reflect amortization for the beneficial conversion feature. See
Class C units
above for a discussion of the Class C units.
|
(2)
|
Inclusion of Class C units in the calculation for the year ended December 31, 2015, would have had an anti-dilutive effect.
|
per barrel except natural gas
|
|
2016
|
|||||
Ethane
|
|
$
|
18.41
|
|
−
|
23.11
|
|
Propane
|
|
47.08
|
|
−
|
52.90
|
|
|
Isobutane
|
|
62.09
|
|
−
|
73.89
|
|
|
Normal butane
|
|
54.62
|
|
−
|
64.93
|
|
|
Natural gasoline
|
|
72.88
|
|
−
|
81.68
|
|
|
Condensate
|
|
76.47
|
|
−
|
81.68
|
|
|
Natural gas (per MMBtu)
|
|
4.87
|
|
−
|
5.96
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2015
|
|
2014
|
|
2013
|
||||||
Gains (losses) on commodity price swap agreements related to sales:
(1)
|
|
|
|
|
|
|
||||||
Natural gas sales
|
|
$
|
45,978
|
|
|
$
|
9,494
|
|
|
$
|
21,382
|
|
Natural gas liquids sales
|
|
145,258
|
|
|
113,866
|
|
|
102,076
|
|
|||
Total
|
|
191,236
|
|
|
123,360
|
|
|
123,458
|
|
|||
Losses on commodity price swap agreements related to purchases
(2)
|
|
(124,944
|
)
|
|
(68,492
|
)
|
|
(85,294
|
)
|
|||
Net gains (losses) on commodity price swap agreements
|
|
$
|
66,292
|
|
|
$
|
54,868
|
|
|
$
|
38,164
|
|
(1)
|
Reported in affiliate natural gas, natural gas liquids and drip condensate sales in the consolidated statements of income in the period in which the related sale is recorded.
|
(2)
|
Reported in cost of product in the consolidated statements of income in the period in which the related purchase is recorded.
|
|
|
DJ Basin Complex
|
|
Hugoton System
|
||||||||||||
per barrel except natural gas
|
|
2015 Swap Prices
|
|
Market Prices
(1)
|
|
2015 Swap Prices
|
|
Market Prices
(1)
|
||||||||
Ethane
|
|
$
|
18.41
|
|
|
$
|
1.96
|
|
|
—
|
|
—
|
||||
Propane
|
|
47.08
|
|
|
13.10
|
|
|
—
|
|
—
|
||||||
Isobutane
|
|
62.09
|
|
|
19.75
|
|
|
—
|
|
—
|
||||||
Normal butane
|
|
54.62
|
|
|
18.99
|
|
|
—
|
|
—
|
||||||
Natural gasoline
|
|
72.88
|
|
|
52.59
|
|
|
—
|
|
—
|
||||||
Condensate
|
|
76.47
|
|
|
52.59
|
|
|
$
|
78.61
|
|
|
$
|
32.56
|
|
||
Natural gas (per MMBtu)
|
|
5.96
|
|
|
2.75
|
|
|
5.50
|
|
|
2.74
|
|
(1)
|
Represents the New York Mercantile Exchange (“NYMEX”) forward strip price as of June 25, 2015, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.
|
|
|
DJ Basin Complex
|
|
Hugoton System
|
||||||||||||
per barrel except natural gas
|
|
2016 Swap Prices
|
|
Market Prices
(1)
|
|
2016 Swap Prices
|
|
Market Prices
(1)
|
||||||||
Ethane
|
|
$
|
18.41
|
|
|
$
|
0.60
|
|
|
—
|
|
—
|
||||
Propane
|
|
47.08
|
|
|
10.98
|
|
|
—
|
|
—
|
||||||
Isobutane
|
|
62.09
|
|
|
17.23
|
|
|
—
|
|
—
|
||||||
Normal butane
|
|
54.62
|
|
|
16.86
|
|
|
—
|
|
—
|
||||||
Natural gasoline
|
|
72.88
|
|
|
26.15
|
|
|
—
|
|
—
|
||||||
Condensate
|
|
76.47
|
|
|
34.65
|
|
|
$
|
78.61
|
|
|
$
|
18.81
|
|
||
Natural gas (per MMBtu)
|
|
5.96
|
|
|
2.11
|
|
|
5.50
|
|
|
2.12
|
|
(1)
|
Represents the NYMEX forward strip price as of December 8, 2015, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2015
|
|
2014
|
|
2013
|
||||||
General and administrative expenses
|
|
$
|
22,896
|
|
|
$
|
20,249
|
|
|
$
|
16,882
|
|
Public company expenses
|
|
8,950
|
|
|
8,006
|
|
|
7,152
|
|
|||
Total reimbursement
|
|
$
|
31,846
|
|
|
$
|
28,255
|
|
|
$
|
24,034
|
|
|
2015
|
|
2014
|
|
2013
|
|||||||||||||||
|
Weighted-Average Grant-Date Fair Value
|
|
Units
|
|
Weighted-Average Grant-Date Fair Value
|
|
Units
|
|
Weighted-Average Grant-Date Fair Value
|
|
Units
|
|||||||||
Phantom units outstanding at beginning of year
|
$
|
60.74
|
|
|
9,522
|
|
|
$
|
49.47
|
|
|
16,844
|
|
|
$
|
41.77
|
|
|
25,619
|
|
Vested
|
60.69
|
|
|
(9,257
|
)
|
|
49.55
|
|
|
(13,122
|
)
|
|
41.28
|
|
|
(14,695
|
)
|
|||
Granted
|
69.10
|
|
|
5,212
|
|
|
68.14
|
|
|
5,800
|
|
|
62.49
|
|
|
5,920
|
|
|||
Phantom units outstanding at end of year
|
68.78
|
|
|
5,477
|
|
|
60.74
|
|
|
9,522
|
|
|
49.47
|
|
|
16,844
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||
|
|
2015
|
|
2014
|
|
2013
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||
thousands
|
|
Purchases
|
|
Sales
|
||||||||||||||||||||
Cash consideration
|
|
$
|
12,664
|
|
|
$
|
22,943
|
|
|
$
|
11,211
|
|
|
$
|
925
|
|
|
$
|
—
|
|
|
$
|
85
|
|
Net carrying value
|
|
7,944
|
|
|
12,210
|
|
|
5,309
|
|
|
972
|
|
|
—
|
|
|
38
|
|
||||||
Partners’ capital adjustment
|
|
$
|
4,720
|
|
|
$
|
10,733
|
|
|
$
|
5,902
|
|
|
$
|
(47
|
)
|
|
$
|
—
|
|
|
$
|
47
|
|
|
|
Year ended December 31,
|
||||||||||
thousands
|
|
2015
|
|
2014
|
|
2013
|
||||||
Revenues and other
(1)
|
|
$
|
1,029,922
|
|
|
$
|
1,053,935
|
|
|
$
|
844,203
|
|
Equity income, net
(1)
|
|
71,251
|
|
|
57,836
|
|
|
22,948
|
|
|||
Cost of product
(1)
|
|
167,420
|
|
|
127,906
|
|
|
136,570
|
|
|||
Operation and maintenance
(2)
|
|
67,119
|
|
|
62,306
|
|
|
59,698
|
|
|||
General and administrative
(3)
|
|
30,692
|
|
|
28,970
|
|
|
24,956
|
|
|||
Operating expenses
|
|
265,231
|
|
|
219,182
|
|
|
221,224
|
|
|||
Interest income
(4)
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
(5)
|
|
14,398
|
|
|
—
|
|
|
—
|
|
|||
Distributions to unitholders
(6)
|
|
314,200
|
|
|
234,024
|
|
|
169,150
|
|
|||
Above-market component of swap extensions with Anadarko
|
|
18,449
|
|
|
—
|
|
|
—
|
|
(1)
|
Represents amounts earned or incurred on and subsequent to the date of acquisition of the Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.
|
(2)
|
Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets.
|
(3)
|
Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see
WES LTIP
and
WGP LTIP and Anadarko Incentive Plans
within this
Note 5
).
|
(4)
|
Represents interest income recognized on the note receivable from Anadarko.
|
(5)
|
For the year ended December 31, 2015, includes accretion expense recognized on the Deferred purchase price obligation - Anadarko for the acquisition of DBJV (see
Note 2
and
Note 12
).
|
(6)
|
Represents distributions paid under the partnership agreement (see
Note 3
and
Note 4
).
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2015
|
|
2014
|
|
2013
|
||||||
Current income tax expense (benefit)
|
|
|
|
|
|
|
||||||
Federal income tax expense (benefit)
|
|
$
|
590
|
|
|
$
|
(1,729
|
)
|
|
$
|
(35,872
|
)
|
State income tax expense (benefit)
|
|
858
|
|
|
63
|
|
|
497
|
|
|||
Total current income tax expense (benefit)
|
|
1,448
|
|
|
(1,666
|
)
|
|
(35,375
|
)
|
|||
Deferred income tax expense (benefit)
|
|
|
|
|
|
|
||||||
Federal income tax expense (benefit)
|
|
348
|
|
|
10,612
|
|
|
40,846
|
|
|||
State income tax expense (benefit)
|
|
1,584
|
|
|
2,713
|
|
|
(811
|
)
|
|||
Total deferred income tax expense (benefit)
|
|
1,932
|
|
|
13,325
|
|
|
40,035
|
|
|||
Total income tax expense (benefit)
|
|
$
|
3,380
|
|
|
$
|
11,659
|
|
|
$
|
4,660
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands except percentages
|
|
2015
|
|
2014
|
|
2013
|
||||||
Income (loss) before income taxes
|
|
$
|
(60,057
|
)
|
|
$
|
419,526
|
|
|
$
|
294,199
|
|
Statutory tax rate
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Tax computed at statutory rate
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Adjustments resulting from:
|
|
|
|
|
|
|
||||||
Federal taxes on income attributable to Partnership assets pre-acquisition
|
|
942
|
|
|
8,988
|
|
|
5,390
|
|
|||
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit)
|
|
27
|
|
|
190
|
|
|
629
|
|
|||
Texas margin tax expense (benefit)
(1)
|
|
2,411
|
|
|
2,481
|
|
|
(1,359
|
)
|
|||
Income tax expense (benefit)
|
|
$
|
3,380
|
|
|
$
|
11,659
|
|
|
$
|
4,660
|
|
Effective tax rate
|
|
(6
|
)%
|
|
3
|
%
|
|
2
|
%
|
(1)
|
Includes a reduction of
$2.2 million
in deferred state income taxes. Texas House Bill 32, signed into law in June 2015, reduced the Texas margin tax rates by
0.25%
. The law became effective January 1, 2016. The Partnership is required to include the impact of the law change on its deferred state income taxes in the period enacted.
|
|
|
December 31,
|
||||||
thousands
|
|
2015
|
|
2014
|
||||
Depreciable property
|
|
$
|
(4,418
|
)
|
|
$
|
(44,725
|
)
|
Credit carryforwards
|
|
512
|
|
|
526
|
|
||
Other intangible assets
|
|
(2,070
|
)
|
|
(1,450
|
)
|
||
Other
|
|
13
|
|
|
7
|
|
||
Net long-term deferred income tax liabilities
|
|
$
|
(5,963
|
)
|
|
$
|
(45,642
|
)
|
|
|
|
|
December 31,
|
||||||
thousands
|
|
Estimated Useful Life
|
|
2015
|
|
2014
|
||||
Land
|
|
n/a
|
|
$
|
3,191
|
|
|
$
|
2,884
|
|
Gathering systems
|
|
3 to 47 years
|
|
5,420,762
|
|
|
4,972,892
|
|
||
Pipelines and equipment
|
|
15 to 45 years
|
|
136,290
|
|
|
151,107
|
|
||
Assets under construction
|
|
n/a
|
|
324,720
|
|
|
483,347
|
|
||
Other
|
|
3 to 40 years
|
|
19,674
|
|
|
16,420
|
|
||
Total property, plant and equipment
|
|
|
|
5,904,637
|
|
|
5,626,650
|
|
||
Accumulated depreciation
|
|
|
|
1,614,663
|
|
|
1,055,207
|
|
||
Net property, plant and equipment
|
|
|
|
$
|
4,289,974
|
|
|
$
|
4,571,443
|
|
|
|
December 31,
|
||||||
thousands
|
|
2015
|
|
2014
|
||||
Gross carrying amount
|
|
$
|
868,035
|
|
|
$
|
892,555
|
|
Accumulated amortization
|
|
(35,908
|
)
|
|
(7,698
|
)
|
||
Other intangible assets
|
|
$
|
832,127
|
|
|
$
|
884,857
|
|
|
Equity Investments
|
||||||||||||||||||||||||||||||
thousands
|
Fort
Union (1) |
|
White
Cliffs (2) |
|
Rendezvous
(3)
|
|
Mont
Belvieu JV (4) |
|
TEG
(5)
|
|
TEP
(6)
|
|
FRP
(7)
|
|
Total
|
||||||||||||||||
Balance at December 31, 2013
|
$
|
25,172
|
|
|
$
|
35,039
|
|
|
$
|
60,928
|
|
|
$
|
122,480
|
|
|
$
|
16,649
|
|
|
$
|
197,731
|
|
|
$
|
135,401
|
|
|
$
|
593,400
|
|
Investment earnings (loss), net of amortization
|
6,344
|
|
|
11,912
|
|
|
1,729
|
|
|
29,029
|
|
|
650
|
|
|
6,108
|
|
|
2,064
|
|
|
57,836
|
|
||||||||
Contributions
|
—
|
|
|
10,456
|
|
|
—
|
|
|
3,957
|
|
|
352
|
|
|
6,623
|
|
|
42,033
|
|
|
63,421
|
|
||||||||
Capitalized interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
857
|
|
|
857
|
|
||||||||
Distributions
|
(5,583
|
)
|
|
(11,330
|
)
|
|
(3,669
|
)
|
|
(34,129
|
)
|
|
(523
|
)
|
|
(5,622
|
)
|
|
(2,111
|
)
|
|
(62,967
|
)
|
||||||||
Distributions in excess of cumulative earnings
(8)
|
—
|
|
|
(1,762
|
)
|
|
(2,652
|
)
|
|
—
|
|
|
(338
|
)
|
|
(6,047
|
)
|
|
(7,256
|
)
|
|
(18,055
|
)
|
||||||||
Balance at December 31, 2014
|
$
|
25,933
|
|
|
$
|
44,315
|
|
|
$
|
56,336
|
|
|
$
|
121,337
|
|
|
$
|
16,790
|
|
|
$
|
198,793
|
|
|
$
|
170,988
|
|
|
$
|
634,492
|
|
Investment earnings (loss), net of amortization
|
(3,200
|
)
|
|
14,770
|
|
|
2,292
|
|
|
23,570
|
|
|
586
|
|
|
16,088
|
|
|
17,145
|
|
|
71,251
|
|
||||||||
Contributions
|
—
|
|
|
8,512
|
|
|
—
|
|
|
(432
|
)
|
|
—
|
|
|
1,880
|
|
|
1,482
|
|
|
11,442
|
|
||||||||
Distributions
|
(5,611
|
)
|
|
(14,188
|
)
|
|
(4,233
|
)
|
|
(24,248
|
)
|
|
(803
|
)
|
|
(16,340
|
)
|
|
(16,631
|
)
|
|
(82,054
|
)
|
||||||||
Distributions in excess of cumulative earnings
(8)
|
—
|
|
|
(2,970
|
)
|
|
(3,482
|
)
|
|
(3,138
|
)
|
|
(290
|
)
|
|
(5,618
|
)
|
|
(746
|
)
|
|
(16,244
|
)
|
||||||||
Balance at December 31, 2015
|
$
|
17,122
|
|
|
$
|
50,439
|
|
|
$
|
50,913
|
|
|
$
|
117,089
|
|
|
$
|
16,283
|
|
|
$
|
194,803
|
|
|
$
|
172,238
|
|
|
$
|
618,887
|
|
(1)
|
The Partnership has a
14.81%
interest in Fort Union, a joint venture that owns a gathering pipeline and treating facilities in the Powder River Basin. Anadarko is the construction manager and physical operator of the Fort Union facilities. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require
65%
or unanimous approval of the owners.
|
(2)
|
The Partnership has a
10%
interest in White Cliffs, a limited liability company that owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than
75%
approval of the members.
|
(3)
|
The Partnership has a
22%
interest in Rendezvous, a limited liability company that operates gas gathering facilities in Southwestern Wyoming. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the members’ gas servicing agreements, require unanimous approval of the members.
|
(4)
|
The Partnership has a
25%
interest in the Mont Belvieu JV, an entity formed to design, construct, and own
two
fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require
50%
or unanimous approval of the owners.
|
(5)
|
The Partnership has a
20%
interest in TEG, an entity that consists of
two
NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than
50%
approval of the members.
|
(6)
|
The Partnership has a
20%
interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than
50%
approval of the members.
|
(7)
|
The Partnership has a
33.33%
interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than
50%
approval of the members.
|
(8)
|
Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2015
|
|
2014
|
|
2013
|
||||||
Consolidated Statements of Income
|
|
|
|
|
|
|
||||||
Revenues
|
|
$
|
668,797
|
|
|
$
|
548,629
|
|
|
$
|
261,705
|
|
Operating income
|
|
381,616
|
|
|
336,188
|
|
|
171,496
|
|
|||
Net income
|
|
381,161
|
|
|
333,705
|
|
|
170,175
|
|
|
|
December 31,
|
||||||
thousands
|
|
2015
|
|
2014
|
||||
Consolidated Balance Sheets
|
|
|
|
|
||||
Current assets
|
|
$
|
156,180
|
|
|
$
|
141,781
|
|
Property, plant and equipment, net
|
|
2,736,553
|
|
|
2,814,336
|
|
||
Other assets
|
|
43,713
|
|
|
48,799
|
|
||
Total assets
|
|
$
|
2,936,446
|
|
|
$
|
3,004,916
|
|
Current liabilities
|
|
78,116
|
|
|
95,102
|
|
||
Non-current liabilities
|
|
9,072
|
|
|
22,615
|
|
||
Equity
|
|
2,849,258
|
|
|
2,887,199
|
|
||
Total liabilities and equity
|
|
$
|
2,936,446
|
|
|
$
|
3,004,916
|
|
|
|
December 31,
|
||||||
thousands
|
|
2015
|
|
2014
|
||||
Trade receivables, net
|
|
$
|
131,221
|
|
|
$
|
105,646
|
|
Other receivables, net
|
|
49,772
|
|
|
3,597
|
|
||
Total accounts receivable, net
|
|
$
|
180,993
|
|
|
$
|
109,243
|
|
|
|
December 31,
|
||||||
thousands
|
|
2015
|
|
2014
|
||||
Natural gas liquids inventory
|
|
$
|
2,403
|
|
|
$
|
5,316
|
|
Imbalance receivables
|
|
2,122
|
|
|
415
|
|
||
Prepaid insurance
|
|
2,296
|
|
|
2,443
|
|
||
Other
|
|
1,034
|
|
|
1,879
|
|
||
Total other current assets
|
|
$
|
7,855
|
|
|
$
|
10,053
|
|
|
|
December 31,
|
||||||
thousands
|
|
2015
|
|
2014
|
||||
Accrued capital expenditures
|
|
$
|
60,702
|
|
|
$
|
128,856
|
|
Accrued plant purchases
|
|
16,425
|
|
|
14,023
|
|
||
Accrued interest expense
|
|
26,194
|
|
|
24,741
|
|
||
Short-term asset retirement obligations
|
|
3,555
|
|
|
1,224
|
|
||
Short-term remediation and reclamation obligations
|
|
1,136
|
|
|
475
|
|
||
Income taxes payable
|
|
770
|
|
|
207
|
|
||
Other
|
|
8,036
|
|
|
1,263
|
|
||
Total accrued liabilities
|
|
$
|
116,818
|
|
|
$
|
170,789
|
|
|
|
Year Ended December 31,
|
||||||
thousands
|
|
2015
|
|
2014
|
||||
Carrying amount of asset retirement obligations at beginning of year
|
|
$
|
110,735
|
|
|
$
|
78,535
|
|
Liabilities incurred
|
|
9,121
|
|
|
13,982
|
|
||
Liabilities settled
|
|
(7,377
|
)
|
|
(4,195
|
)
|
||
Accretion expense
|
|
5,943
|
|
|
4,879
|
|
||
Revisions in estimated liabilities
|
|
2,105
|
|
|
17,534
|
|
||
Carrying amount of asset retirement obligations at end of year
|
|
$
|
120,527
|
|
|
$
|
110,735
|
|
|
|
December 31, 2015
|
|
December 31, 2014
|
||||||||||||||||||||
thousands
|
|
Principal
|
|
Carrying
Value
|
|
Fair
Value
(1)
|
|
Principal
|
|
Carrying
Value
|
|
Fair
Value
(1)
|
||||||||||||
2021 Notes
|
|
$
|
500,000
|
|
|
$
|
496,285
|
|
|
$
|
513,645
|
|
|
$
|
500,000
|
|
|
$
|
495,714
|
|
|
$
|
549,530
|
|
2022 Notes
|
|
670,000
|
|
|
672,572
|
|
|
595,744
|
|
|
670,000
|
|
|
672,930
|
|
|
681,942
|
|
||||||
2018 Notes
|
|
350,000
|
|
|
350,348
|
|
|
339,293
|
|
|
350,000
|
|
|
350,474
|
|
|
352,162
|
|
||||||
2044 Notes
|
|
400,000
|
|
|
393,923
|
|
|
321,499
|
|
|
400,000
|
|
|
393,836
|
|
|
417,619
|
|
||||||
2025 Notes
|
|
500,000
|
|
|
494,229
|
|
|
422,285
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
RCF
|
|
300,000
|
|
|
300,000
|
|
|
300,000
|
|
|
510,000
|
|
|
510,000
|
|
|
510,000
|
|
||||||
Total long-term debt
|
|
$
|
2,720,000
|
|
|
$
|
2,707,357
|
|
|
$
|
2,492,466
|
|
|
$
|
2,430,000
|
|
|
$
|
2,422,954
|
|
|
$
|
2,511,253
|
|
(1)
|
Fair value is measured using the market approach and Level 2 inputs.
|
thousands
|
|
Carrying Value
|
||
Balance at December 31, 2013
|
|
$
|
1,418,169
|
|
RCF borrowings
|
|
1,160,000
|
|
|
Issuance of 2044 Notes
|
|
400,000
|
|
|
Issuance of 2018 Notes
|
|
100,000
|
|
|
Repayments of RCF borrowings
|
|
(650,000
|
)
|
|
Other
|
|
(5,215
|
)
|
|
Balance at December 31, 2014
|
|
$
|
2,422,954
|
|
RCF borrowings
|
|
400,000
|
|
|
Issuance of 2025 Notes
|
|
500,000
|
|
|
Repayments of RCF borrowings
|
|
(610,000
|
)
|
|
Other
|
|
(5,597
|
)
|
|
Balance at December 31, 2015
|
|
$
|
2,707,357
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2015
|
|
2014
|
|
2013
|
||||||
Third parties
|
|
|
|
|
|
|
||||||
Long-term debt
|
|
$
|
102,058
|
|
|
$
|
81,495
|
|
|
$
|
59,293
|
|
Amortization of debt issuance costs and commitment fees
|
|
5,734
|
|
|
5,103
|
|
|
4,449
|
|
|||
Capitalized interest
|
|
(8,318
|
)
|
|
(9,832
|
)
|
|
(11,945
|
)
|
|||
Total interest expense – third parties
|
|
99,474
|
|
|
76,766
|
|
|
51,797
|
|
|||
Affiliates
|
|
|
|
|
|
|
||||||
Deferred purchase price obligation – Anadarko
(1)
|
|
14,398
|
|
|
—
|
|
|
—
|
|
|||
Total interest expense – affiliates
|
|
14,398
|
|
|
—
|
|
|
—
|
|
|||
Interest expense
|
|
$
|
113,872
|
|
|
$
|
76,766
|
|
|
$
|
51,797
|
|
(1)
|
See
Note 2
for a discussion of the accretion and net present value of the Deferred purchase price obligation - Anadarko.
|
thousands
|
Operating Leases
|
||
2016
|
$
|
2,614
|
|
2017
|
1,705
|
|
|
2018
|
109
|
|
|
2019
|
—
|
|
|
2020
|
—
|
|
|
Thereafter
|
—
|
|
|
Total
|
$
|
4,428
|
|
thousands except per-unit amounts
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
2015
|
|
|
|
|
|
|
|
||||||||
Total revenues and other
|
$
|
388,409
|
|
|
$
|
416,572
|
|
|
$
|
385,101
|
|
|
$
|
371,290
|
|
Equity income, net
|
18,220
|
|
|
18,941
|
|
|
21,976
|
|
|
12,114
|
|
||||
Gain on divestiture and other, net
|
—
|
|
|
—
|
|
|
77,244
|
|
|
(20,224
|
)
|
||||
Operating income (loss)
(1)
|
(154,484
|
)
|
|
138,038
|
|
|
195,809
|
|
|
(141,829
|
)
|
||||
Net income (loss)
(1)
|
(176,564
|
)
|
|
116,440
|
|
|
166,477
|
|
|
(169,790
|
)
|
||||
Net income (loss) attributable to Western Gas Partners, LP
(1)
|
(179,790
|
)
|
|
113,624
|
|
|
164,289
|
|
|
(171,661
|
)
|
||||
Net income (loss) per common unit – basic and diluted
(1) (2)
|
(1.61
|
)
|
|
0.46
|
|
|
0.79
|
|
|
(1.60
|
)
|
||||
2014
|
|
|
|
|
|
|
|
||||||||
Total revenues and other
|
$
|
301,249
|
|
|
$
|
357,381
|
|
|
$
|
357,521
|
|
|
$
|
366,717
|
|
Equity income, net
|
9,251
|
|
|
13,008
|
|
|
19,063
|
|
|
16,514
|
|
||||
Operating income (loss)
|
105,792
|
|
|
121,565
|
|
|
133,469
|
|
|
117,702
|
|
||||
Net income (loss)
|
94,748
|
|
|
102,617
|
|
|
113,022
|
|
|
97,480
|
|
||||
Net income (loss) attributable to Western Gas Partners, LP
|
91,056
|
|
|
99,167
|
|
|
109,159
|
|
|
94,460
|
|
||||
Net income (loss) per common unit – basic and diluted
(2)
|
0.54
|
|
|
0.57
|
|
|
0.60
|
|
|
0.42
|
|
(1)
|
Includes impairments at the Red Desert complex in the first and fourth quarters of 2015 and at the Hilight system in the fourth quarter of 2015. See
Note 7—Property, Plant and Equipment
.
|
(2)
|
Represents net income (loss) earned on and subsequent to the acquisition of the Partnership assets (as defined in
Note 1—Summary of Significant Accounting Policies
).
|
Name
|
|
Age
|
|
Position with Western Gas Holdings, LLC
|
|
Robert G. Gwin
|
|
52
|
|
|
Chairman of the Board
|
Donald R. Sinclair
|
|
58
|
|
|
President, Chief Executive Officer and Director
|
Benjamin M. Fink
|
|
45
|
|
|
Senior Vice President, Chief Financial Officer and Treasurer
|
Jacqueline A. Dimpel
|
|
49
|
|
|
Senior Vice President
|
Philip H. Peacock
|
|
44
|
|
|
Vice President, General Counsel and Corporate Secretary
|
Steven D. Arnold
|
|
55
|
|
|
Director
|
Milton Carroll
|
|
65
|
|
|
Director
|
James R. Crane
|
|
62
|
|
|
Director
|
Darrell E. Hollek
|
|
58
|
|
|
Director (effective May 13, 2015)
|
Robert K. Reeves
|
|
58
|
|
|
Director
|
David J. Tudor
|
|
56
|
|
|
Director
|
Robert G. Gwin
Age: 52
Houston, Texas
Director since:
August 2007
Not Independent
Officer From:
August 2007 to
January 2010
|
Biography/Qualifications
Robert G. Gwin has served as a director of our general partner since August 2007 and has served as Chairman of the Board of our general partner since October 2009. He also served as Chief Executive Officer of our general partner from August 2007 to January 2010 and as President from August 2007 to September 2009. Mr. Gwin has also served as Chairman of the Board of WGP GP since September 2012. He was named Executive Vice President, Finance and Chief Financial Officer of Anadarko in May 2013 and previously served as Senior Vice President, Finance and Chief Financial Officer beginning in 2009. Mr. Gwin also serves as Chairman of the Board of LyondellBasell Industries N.V.
|
|
|
Donald R. Sinclair
Age: 58
Houston, Texas
Director since:
October 2009
Not Independent
Officer Since:
October 2009
|
Biography/Qualifications
Donald R. Sinclair has served as President and a director of our general partner since October 2009 and as Chief Executive Officer since January 2010. Mr. Sinclair has served as the President and Chief Executive Officer and as a director of WGP GP since September 2012. He was named a Senior Vice President of Anadarko in May 2013, prior to which he served as a Vice President of Anadarko beginning in 2010. Prior to joining Anadarko and becoming President and a director of our general partner, Mr. Sinclair was a founding partner and served as President of Ceritas Energy, LLC, a midstream energy company headquartered in Houston with operations in Texas, Wyoming and Utah from 2003 to 2009. Mr. Sinclair has worked in the oil and gas industry for over 33 years, with a focus on marketing and trading and the midstream sector.
|
|
|
Benjamin M. Fink
Age: 45
Houston, Texas
Officer since:
May 2009
|
Biography/Qualifications
Benjamin M. Fink has served as the Senior Vice President and Chief Financial Officer of our general partner since 2009, and as Senior Vice President, Chief Financial Officer and Treasurer of our general partner since 2010. Mr. Fink has served as Senior Vice President, Chief Financial Officer and Treasurer of WGP GP since September 2012. He was Director, Finance of Anadarko from 2007 to 2009, during which time he was responsible for principal oversight of the finance operations of an Anadarko subsidiary, Anadarko Algeria Company, LLC. From 2006 to 2007, he served as an independent financial consultant to Anadarko in its Beijing, China and Rio de Janeiro, Brazil offices. From 2001 until 2006, he held executive management positions at Prosoft Learning Corporation, including serving as its President and Chief Executive Officer from 2004 until that company’s sale in 2006. From 2000 to 2001 he co-founded and served as Chief Operating Officer and Chief Financial Officer of Meta4 Group Limited, an online direct marketer based in Hong Kong and Tokyo. Previously, he held positions of increasing responsibility at Prudential Capital Group and Prudential Asset Management Asia, where he focused on the negotiation, structuring and execution of private debt and equity investments.
|
|
|
Jacqueline A. Dimpel
Age: 49
Houston, Texas
Officer since:
February 2014
|
Biography/Qualifications
Jacqueline A. Dimpel has served as Senior Vice President and principal operating officer for our general partner and for WGP GP since February 2014. She also has served as Vice President of Midstream for Anadarko since December 2013. Since joining Anadarko in 2006, Ms. Dimpel has served in a variety of technical, operational and planning positions, including Business Advisor for U.S. Onshore Operations and Midstream Operations Manager for the Southern and Appalachia region. Prior to joining Anadarko, Ms. Dimpel served in engineering roles of increasing responsibility with ExxonMobil. Ms. Dimpel is a professional licensed Mechanical Engineer in California and Texas and is a member of the Society of Petroleum Engineers.
|
|
|
Philip H. Peacock
Age: 44
Houston, Texas
Officer since:
August 2012
|
Biography/Qualifications
Philip H. Peacock has served as Vice President, General Counsel and Corporate Secretary of our general partner since August 2012. Mr. Peacock has served as Vice President, General Counsel and Corporate Secretary of WGP GP since September 2012. Prior to joining Western Gas, Mr. Peacock was a partner practicing corporate and securities law at the law firm of Andrews Kurth LLP, which he joined in 2003. He is licensed to practice law in the state of Texas.
|
|
|
Steven D. Arnold
Age: 55
Houston, Texas
Director since:
February 2014
Independent
|
Biography/Qualifications
Steven D. Arnold has served as a director of our general partner and as a member of the Special Committee and Audit Committee of the Board of Directors of our general partner since February 2014. Mr. Arnold served on the Board of Directors of the general partner of Spectra Energy Partners, LP from 2007 to December 2013, during which time he served on that board’s Audit Committee and Conflicts Committee. He served as Chairman of each of those committees at separate times during his board membership. Mr. Arnold is engaged in private investment management and consulting services in Houston, Texas through 3 Lights Management Co., serving as its President since inception in 2000. Mr. Arnold has over ten years of institutional investment management experience with Prudential Financial, Inc. Mr. Arnold brings strong risk assessment and strategic expertise to the board.
|
|
|
Milton Carroll
Age: 65
Houston, Texas
Director since:
April 2008
Independent
|
Biography/Qualifications
Milton Carroll has served as a director of our general partner and as Chairman of the Special Committee of the Board of Directors of our general partner since 2008. Mr. Carroll currently serves as Executive Chairman of Houston-based CenterPoint Energy, Inc., where he has been a director since 1992. He also serves as Chairman of Health Care Services Corporation (a Chicago-based company operating through its Blue Cross and Blue Shield divisions in Illinois, Texas, Oklahoma, New Mexico, and Montana), as a director of Halliburton Company, where he serves as a member of the Compensation Committee and the Nominating and Corporate Governance Committee, and as a director of LyondellBasell Industries N.V., where he serves as a member of the Nominating and Governance Committee and the Compensation Committee. Mr. Carroll served as a director of the general partner of LRR Energy, LP from November 2011 to January 2014. Mr. Carroll also served as a director of EGL, Inc. from 2003 until 2007 and as a director of the general partner of DCP Midstream Partners, LP from 2005 to 2006.
|
|
|
James R. Crane
Age: 62
Houston, Texas
Director since:
April 2008
Independent
|
Biography/Qualifications
James R. Crane has served as a director of our general partner and as a member of the Special Committee and Audit Committee of the Board of Directors of our general partner since April 2008. In November 2011, Mr. Crane became the principal owner and Chairman of the Houston Astros Baseball Club. Mr. Crane is also the Chairman and Chief Executive Officer of Crane Capital Group Inc., an investment management company he founded. Crane Capital Group currently invests in transportation, power distribution, real estate and asset management. Its holdings include Crane Worldwide Logistics, a premier global provider of customized transportation and logistics services with 54 offices in 20 countries, and Champion Energy Services, a retail electric provider. Prior to founding Crane Capital Group Inc., he was founder, Chairman and Chief Executive Officer of EGL, Inc., a global transportation, supply chain management and information services company, from 1984 until its sale in 2007. Mr. Crane currently serves as a director of Nabors Industries Ltd., an international drilling contractor and well-services provider. From February 2010 to February 2012, he served as a director of Fort Dearborn Life Insurance Company, a subsidiary of Health Care Service Corporation, and from 1999 to 2007 he served as a director of HCC Insurance Holdings, Inc.
|
|
|
Darrell E. Hollek
Age: 58
Houston, Texas
Director since:
May 2015
Not Independent
|
Biography/Qualifications
Darrell E. Hollek has served as a director of our general partner and as a director of WGP GP since May 2015. Mr. Hollek was named Executive Vice President, U.S. Onshore Exploration and Production of Anadarko in April 2015. Prior to this position, he served as Senior Vice President, Operations (Deepwater Americas) of Anadarko since May 2013. Prior to this position, he served as Vice President, Operations of Anadarko since 2007. Mr. Hollek joined Anadarko upon the acquisition of Kerr-McGee Corporation in 2006. He has held positions of increasing responsibility with Anadarko and Kerr-McGee Corporation, where he began his career, including management roles in the Gulf of Mexico, U.S. Onshore and Environmental, Health, Safety and Regulatory.
|
|
|
Robert K. Reeves
Age: 58
Houston, Texas
Director since:
August 2007
Not Independent
|
Biography/Qualifications
Robert K. Reeves has served as a director of our general partner since 2007 and as a director of WGP GP since September 2012. Mr. Reeves was named Executive Vice President, Law and Chief Administrative Officer of Anadarko in September 2015 and previously served as Executive Vice President, General Counsel and Chief Administrative Officer since May 2013 and as Senior Vice President, General Counsel and Chief Administrative Officer since 2007. He has also served as a director of Key Energy Services, Inc., a publicly traded oil field services company, since 2007. Prior to joining Anadarko, he served as Executive Vice President, Administration and General Counsel of North Sea New Ventures from 2003 to 2004 and as Executive Vice President, General Counsel and Secretary of Ocean Energy, Inc. and its predecessor companies from 1997 to 2003.
|
|
|
David J. Tudor
Age: 56
Houston, Texas
Director since:
April 2008
Independent
|
Biography/Qualifications
David J. Tudor has served as a director of our general partner and as Chairman of the Audit Committee of the Board of Directors of our general partner since 2008, and previously served as a member of the Special Committee of the Board of Directors of our general partner from 2008 to December 2012. Mr. Tudor has served as a director of WGP GP and as Chairman of the Audit Committee of its Board of Directors since December 2012. Since May 2013, Mr. Tudor has served as President and Chief Executive Officer of Champion Energy Services, a retail electric provider serving residential, governmental, commercial and industrial customers in a growing number of deregulated electric energy markets throughout the United States. From 1999 through 2013, Mr. Tudor was the President and Chief Executive Officer of ACES, an Indianapolis-based commodity risk management company owned by 21 generation and transmission cooperatives throughout the United States. Prior to joining ACES, Mr. Tudor was the Executive Vice President & Chief Operating Officer of PG&E Energy Trading, where he managed commercial operations in the United States and Canada.
|
Officers of Our General Partner
|
|
Time
Allocated
|
|
Anadarko Corporate Officer
|
Donald R. Sinclair
|
|
75.0%
|
|
Yes
|
Benjamin M. Fink
|
|
90.0%
|
|
Yes
|
Jacqueline A. Dimpel
|
|
25.0%
|
|
Yes
|
Philip H. Peacock
|
|
50.0%
|
|
No
|
•
|
base salary;
|
•
|
annual cash incentives;
|
•
|
equity-based compensation, which includes equity-based compensation under Anadarko’s 2012 Omnibus Incentive Compensation Plan (the “Omnibus Plan”); and
|
•
|
Anadarko’s other benefits, including welfare and retirement benefits, severance benefits and change of control benefits, plus other benefits on the same basis as other eligible Anadarko employees.
|
•
|
retirement benefits to match competitive practices in Anadarko’s industry, including participation in Anadarko’s employee savings plan, savings restoration plan, retirement plan and retirement restoration plan;
|
•
|
severance benefits under the Anadarko Officer Severance Plan;
|
•
|
certain change of control benefits under key employee change of control contracts;
|
•
|
director and officer indemnification agreements;
|
•
|
a limited number of perquisites, including financial counseling, tax preparation and estate planning, an executive physical program, management life insurance, voluntary participation in the Deferred Compensation Plan, and personal excess liability insurance; and
|
•
|
benefits, including medical, dental, vision, flexible spending and health savings accounts, paid time off, life insurance and disability coverage, which are also provided to all other eligible U.S.-based Anadarko employees.
|
Name and Principal Position
|
|
Year
|
|
Salary
($)
(1)
|
|
Bonus
($)
|
|
Stock
Awards
($)
(2)
|
|
Option
Awards
($)
(3)
|
|
Non-Equity
Incentive Plan Compensation
($)
(4)
|
|
All Other
Compensation
($)
(5)
|
|
Total
($)
|
|||||||
Donald R. Sinclair
|
|
2015
|
|
350,481
|
|
|
—
|
|
|
828,646
|
|
|
449,573
|
|
|
336,462
|
|
|
104,969
|
|
|
2,070,131
|
|
President and
|
|
2014
|
|
304,327
|
|
|
—
|
|
|
807,851
|
|
|
436,272
|
|
|
292,154
|
|
|
77,370
|
|
|
1,917,974
|
|
Chief Executive Officer
|
2013
|
|
283,414
|
|
|
—
|
|
|
843,813
|
|
|
280,588
|
|
|
243,736
|
|
|
123,110
|
|
|
1,774,661
|
|
|
Benjamin M. Fink
|
|
2015
|
|
341,135
|
|
|
—
|
|
|
672,651
|
|
|
364,951
|
|
|
266,085
|
|
|
102,170
|
|
|
1,746,992
|
|
Senior Vice President, Chief
|
|
2014
|
|
300,635
|
|
|
—
|
|
|
646,283
|
|
|
349,017
|
|
|
234,495
|
|
|
76,436
|
|
|
1,606,866
|
|
Financial Officer and Treasurer
|
2013
|
|
280,904
|
|
|
—
|
|
|
760,623
|
|
|
202,020
|
|
|
191,015
|
|
|
121,704
|
|
|
1,556,266
|
|
|
Jacqueline A. Dimpel
|
|
2015
|
|
93,462
|
|
|
—
|
|
|
138,778
|
|
|
75,281
|
|
|
72,900
|
|
|
27,992
|
|
|
408,413
|
|
Senior Vice President
|
|
2014
|
|
82,260
|
|
|
—
|
|
|
273,490
|
|
|
139,580
|
|
|
64,163
|
|
|
20,945
|
|
|
580,438
|
|
Philip H. Peacock
|
|
2015
|
|
134,935
|
|
|
—
|
|
|
85,010
|
|
|
—
|
|
|
64,769
|
|
|
40,413
|
|
|
325,127
|
|
Vice President, General Counsel
|
|
2014
|
|
128,510
|
|
|
—
|
|
|
87,515
|
|
|
—
|
|
|
61,685
|
|
|
30,766
|
|
|
308,476
|
|
and Corporate Secretary
|
|
2013
|
|
121,154
|
|
|
—
|
|
|
70,016
|
|
|
—
|
|
|
58,154
|
|
|
52,482
|
|
|
301,806
|
|
(1)
|
The amounts in this column reflect the base salary compensation allocated to us by Anadarko for the years ended
December 31, 2015
,
2014
and
2013
.
|
(2)
|
The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for non-option stock awards granted pursuant to the WES LTIP, the WGP LTIP and the 2012 Anadarko Omnibus Incentive Compensation Plans and include unvested amounts. For awards of phantom units granted under the WES LTIP and WGP LTIP, the grant date value is determined by multiplying the number of phantom units awarded by the per-unit closing price of the underlying common units on the date of grant. For a discussion of valuation assumptions for the awards under the 2012 Anadarko Omnibus Incentive Compensation Plans, see
Note 19—Share-Based Compensation
in the
Notes to Consolidated Financial Statements
included under Part II, Item 8 of Anadarko’s Form 10-K for the year ended
December 31, 2015
(which is not, and shall not be deemed to be, incorporated by reference herein). For information regarding the non-option stock awards granted to the named executives in
2015
, see the Grants of Plan-Based Awards Table. The amounts in this column also reflect the allocation of Anadarko performance unit awards, where such gross amounts are subject to market conditions and have been valued based on the probable outcome of the market conditions as of the grant date.
|
(3)
|
The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for option awards granted pursuant to the 2012 Anadarko Omnibus Incentive Compensation Plans. See note (2) above for valuation assumptions. For information regarding the option awards granted to the named executives in
2015
, see the Grants of Plan-Based Awards Table.
|
(4)
|
The amounts in this column reflect the compensation under the Anadarko annual incentive program expected to be allocated to us for the year ended
December 31, 2015
, and allocated to us for the years ended December 31,
2014
and
2013
. The
2015
amounts represent payments which were earned in
2015
and are expected to be paid in early
2016
, the
2014
amounts represent payments which were earned in
2014
and paid in early
2015
and the
2013
amounts represent the payments which were earned in
2013
and paid in early
2014
. For an explanation of the
2015
annual incentive plan awards, read
Compensation Discussion and Analysis – Analysis of
2015
Compensation Actions – Performance-Based Annual Cash Incentives (Bonuses),
contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
March 31, 2016
.
|
(5)
|
The amounts in this column reflect the compensation expenses related to Anadarko’s retirement and savings plans that were allocated to us for the years ended
December 31, 2015
,
2014
and
2013
. The
2015
allocated expenses are detailed in the table below:
|
Name
|
|
Retirement Plan Expense
|
|
Savings Plan
Expense
|
||||
Donald R. Sinclair
|
|
$
|
72,213
|
|
|
$
|
32,756
|
|
Benjamin M. Fink
|
|
70,287
|
|
|
31,883
|
|
||
Jacqueline A. Dimpel
|
|
19,257
|
|
|
8,735
|
|
||
Philip H. Peacock
|
|
27,802
|
|
|
12,611
|
|
|
|
|
|
|
|
|
|
|
|
All
Other
Stock
Awards:
Number of
Shares of
Stock or
Units
(#)
(3)
|
|
All Other
Option
Awards:
Number of
Securities
Underlying
Options
(#)
(4)
|
|
Exercise
or
Base Price
of Option
Awards
($/Sh)
|
|
Grant
Date
Fair Value
of Stock
and
Option
Awards
($)
(5)
|
||||||||||||||
|
|
Estimated Future Payouts
Under Non-Equity
Incentive Plan Awards
(1)
|
|
Estimated Future Payouts Under
Equity Incentive Plan Awards
(2)
|
|
|
|
|
||||||||||||||||||||||
Name and Grant Date
|
|
Threshold
($)
|
|
Target
($)
|
|
Maximum
($)
|
|
Threshold
(#)
|
|
Target
(#)
|
|
Maximum
(#)
|
|
|
|
|
||||||||||||||
Donald R. Sinclair
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
280,385
|
|
|
336,462
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
10/26/15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,620
|
|
|
|
|
|
|
318,780
|
|
||||||||
10/26/15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24,870
|
|
|
69.00
|
|
|
449,573
|
|
|||||||
10/26/15
|
|
|
|
|
|
|
|
2,851
|
|
|
7,128
|
|
|
14,256
|
|
|
|
|
|
|
|
|
509,866
|
|
||||||
Benjamin M. Fink
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
221,738
|
|
|
266,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
10/26/15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,750
|
|
|
|
|
|
|
258,771
|
|
||||||||
10/26/15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,189
|
|
|
69.00
|
|
|
364,951
|
|
|||||||
10/26/15
|
|
|
|
|
|
|
|
2,134
|
|
|
5,786
|
|
|
11,572
|
|
|
|
|
|
|
|
|
413,880
|
|
||||||
Jacqueline A. Dimpel
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
60,750
|
|
|
72,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
10/26/15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
774
|
|
|
|
|
|
|
53,389
|
|
||||||||
10/26/15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,165
|
|
|
69.00
|
|
|
75,281
|
|
|||||||
10/26/15
|
|
|
|
|
|
|
|
478
|
|
|
1,194
|
|
|
2,388
|
|
|
|
|
|
|
|
|
85,389
|
|
||||||
Philip H. Peacock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
53,974
|
|
|
64,769
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
03/09/15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,053
|
|
|
|
|
|
|
85,010
|
|
(1)
|
Reflects the estimated
2015
cash payouts allocable to us under Anadarko’s annual incentive plan. If threshold levels of performance are not met, then the payout can be zero. The maximum value reflects the maximum amount allocable to us consistent with the methodologies set forth in the services and secondment agreement. The expense expected to be allocated to us for the actual bonus payouts under the annual incentive program for
2015
is reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. For additional discussion of Anadarko’s annual incentive plan, read
Compensation Discussion and Analysis — Analysis of
2015
Compensation Actions — Performance-Based Annual Cash Incentives (Bonuses)
contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
March 31, 2016
.
|
(2)
|
Reflects the estimated future payout allocable to us under Anadarko’s performance units awarded in
2015
. Under the performance unit program, participants may earn from 0% to 200% of the targeted award based on Anadarko’s relative total shareholder return performance over a specified performance period. The performance units granted to Messrs. Sinclair and Fink and Ms. Dimpel on October 26, 2015, are subject to a three-year performance period. If earned, the awards are to be paid in cash rather than equity. The threshold value represents the minimum payment (other than zero) that may be earned. For additional discussion of Anadarko’s performance unit awards, read
Compensation Discussion and Analysis — Analysis of
2015
Compensation Actions — Equity Compensation
contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
March 31, 2016
.
|
(3)
|
Reflects the allocable number of restricted stock shares and restricted stock units awarded in
2015
under the Omnibus Plan. These awards vest equally over three years, beginning with the first anniversary of the grant date. For restricted stock shares, dividends are paid current. For restricted stock units, dividend equivalents are reinvested in shares of Anadarko common stock and paid upon the applicable vesting of the underlying award.
|
(4)
|
Reflects the allocable number of Anadarko stock options each named executive officer was awarded in
2015
. These awards vest equally over three years, beginning with the first anniversary of the date of grant and have a term of seven years.
|
(5)
|
The amounts included in the Grant Date Fair Value of Stock and Option Awards column represent the expected allocation to us of the grant date fair value of the awards made to named executives in
2015
computed in accordance with FASB ASC Topic 718. The value ultimately realized by the executive upon the actual vesting of the award(s) or the exercise of the stock option(s) may or may not be equal to the determined value. For a discussion of valuation assumptions for the awards under the Omnibus Plan, see
Note 19—Share-Based Compensation
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of Anadarko’s Form 10-K for the year ended
December 31, 2015
(which is not, and shall not be deemed to be, incorporated by reference herein).
|
(1)
|
The table below shows the vesting dates for the respective unexercisable stock options listed in the above Outstanding Equity Awards Table:
|
Vesting Date
|
|
Donald R. Sinclair
|
|
Benjamin M. Fink
|
|
Jacqueline A. Dimpel
|
|
Philip H. Peacock
|
||||
01/08/2016
|
|
—
|
|
|
—
|
|
|
980
|
|
|
—
|
|
06/07/2016
|
|
—
|
|
|
484
|
|
|
—
|
|
|
—
|
|
11/06/2016
|
|
3,606
|
|
|
2,020
|
|
|
—
|
|
|
—
|
|
11/06/2016
|
|
6,173
|
|
|
4,938
|
|
|
1,060
|
|
|
—
|
|
10/26/2016
|
|
8,291
|
|
|
6,730
|
|
|
1,388
|
|
|
—
|
|
01/08/2017
|
|
—
|
|
|
—
|
|
|
980
|
|
|
—
|
|
11/06/2017
|
|
6,173
|
|
|
4,938
|
|
|
1,060
|
|
|
—
|
|
10/26/2017
|
|
8,290
|
|
|
6,729
|
|
|
1,388
|
|
|
—
|
|
10/26/2018
|
|
8,290
|
|
|
6,729
|
|
|
1,388
|
|
|
—
|
|
(2)
|
The table below shows the vesting dates for the respective phantom units, restricted stock shares and restricted stock units listed in the above Outstanding Equity Awards Table:
|
Vesting Date
|
|
Donald R. Sinclair
|
|
Benjamin M. Fink
|
|
Jacqueline A. Dimpel
|
|
Philip H. Peacock
|
||||
01/08/2016
|
|
—
|
|
|
—
|
|
|
203
|
|
|
—
|
|
03/06/2016
|
|
—
|
|
|
—
|
|
|
—
|
|
|
337
|
|
03/07/2016
|
|
—
|
|
|
978
|
|
|
161
|
|
|
282
|
|
03/09/2016
|
|
—
|
|
|
—
|
|
|
—
|
|
|
351
|
|
06/07/2016
|
|
—
|
|
|
177
|
|
|
—
|
|
|
—
|
|
10/26/2016
|
|
1,549
|
|
|
1,256
|
|
|
259
|
|
|
—
|
|
11/06/2016
|
|
1,050
|
|
|
587
|
|
|
—
|
|
|
—
|
|
11/06/2016
|
|
1,125
|
|
|
899
|
|
|
193
|
|
|
|
|
11/20/2016
|
|
4,561
|
|
|
2,554
|
|
|
—
|
|
|
—
|
|
01/08/2017
|
|
—
|
|
|
—
|
|
|
203
|
|
|
—
|
|
03/06/2017
|
|
—
|
|
|
—
|
|
|
—
|
|
|
337
|
|
03/09/2017
|
|
—
|
|
|
—
|
|
|
—
|
|
|
351
|
|
10/26/2017
|
|
1,548
|
|
|
1,256
|
|
|
259
|
|
|
—
|
|
11/06/2017
|
|
1,125
|
|
|
900
|
|
|
193
|
|
|
—
|
|
03/09/2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
351
|
|
10/26/2018
|
|
1,548
|
|
|
1,256
|
|
|
260
|
|
|
—
|
|
(3)
|
The table below shows the performance periods for the respective performance units listed in the above Outstanding Equity Awards Table. Generally, the number of outstanding units for each award is calculated based on Anadarko’s relative performance ranking as of
December 31, 2015
, and is not necessarily indicative of what the payout percent earned will be at the end of the performance period. As of
December 31, 2015
, the performance to date calculation for awards with performance periods beginning January 1, 2014, was 92% and for awards with performance periods beginning January 1,
2015
, was 40%. For awards that were granted in 2015 with performance periods beginning January 1,
2016
, target payout has been assumed.
|
Performance Period
|
|
APC Performance
to Date Payout % |
|
Donald R. Sinclair
Performance
Units
|
|
Benjamin M. Fink
Performance
Units
|
|
Jacqueline A. Dimpel
Performance
Units
|
|||
1/1/2014 to 12/31/2015
|
|
92%
|
|
—
|
|
|
—
|
|
|
401
|
|
1/1/2014 to 12/31/2016
|
|
92%
|
|
—
|
|
|
—
|
|
|
401
|
|
1/1/2015 to 12/31/2017
|
|
40%
|
|
1,995
|
|
|
1,596
|
|
|
343
|
|
1/1/2016 to 12/31/2018
|
|
100%
|
|
7,128
|
|
|
5,786
|
|
|
1,194
|
|
(4)
|
These awards represent grants of phantom units under the WGP LTIP. The market values for these awards are based on the closing common unit price for WGP on
December 31, 2015
, of
$36.29
.
|
|
|
Option Awards
|
|
Stock Awards
|
||||||||
Name
|
|
Number of Shares Acquired on Exercise (#)
(1)
|
|
Value Realized on Exercise ($)
(1)
|
|
Number of Shares Acquired on Vesting (#)
(2)
|
|
Value Realized on Vesting ($)
(2)
|
||||
Donald R. Sinclair
|
|
—
|
|
|
—
|
|
|
9,936
|
|
|
493,135
|
|
Benjamin M. Fink
|
|
1,598
|
|
|
24,650
|
|
|
6,238
|
|
|
380,960
|
|
Jacqueline A. Dimpel
|
|
—
|
|
|
—
|
|
|
699
|
|
|
54,219
|
|
Philip H. Peacock
|
|
—
|
|
|
—
|
|
|
981
|
|
|
75,296
|
|
(1)
|
Shares acquired and values realized on exercise include options exercised in
2015
. The actual value ultimately realized by the named executive officer may be more or less than the realized value calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise.
|
(2)
|
Shares acquired and values realized on vesting reflect the taxable value to the named executive officer as of the date of the vesting in
2015
of restricted stock shares or units, performance units, or phantom units. For restricted stock shares or units and phantom units, the actual value ultimately realized by the named executive officer may be more or less than the value realized calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise or vesting occurrence.
|
Name
|
|
Accelerated WGP LTIP Awards
(1)
|
||
Donald R. Sinclair
|
|
$
|
165,519
|
|
Benjamin M. Fink
|
|
92,685
|
|
|
Jacqueline A. Dimpel
|
|
—
|
|
|
Philip H. Peacock
|
|
—
|
|
(1)
|
WGP LTIP phantom units are valued based on the closing WGP common unit price of
$36.29
on
December 31, 2015
.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Cash Severance
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Mr. Sinclair
(1)
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Prorated Portion of Performance Unit Awards
(2)
|
$
|
32,301
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total
|
$
|
32,301
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
As of December 31, 2015, Mr. Sinclair was eligible for retirement.
|
(2)
|
Under the terms of the performance unit agreements, retirement-eligible participants receive a prorated payout, paid after the end of the performance period, based on actual performance and the number of months worked during the performance period. Mr. Sinclair’s value reflects an estimated payout based on performance to date through December 31, 2015, which is not indicative of the payout that he will receive at the end of the performance period based on actual performance.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Cash Severance
(1)
|
$
|
945,000
|
|
|
$
|
870,525
|
|
|
$
|
238,500
|
|
|
$
|
—
|
|
Pro-rata Bonus
(2)
|
336,462
|
|
|
266,085
|
|
|
72,900
|
|
|
—
|
|
||||
Accelerated Anadarko Equity Compensation
(3)
|
829,106
|
|
|
713,736
|
|
|
178,333
|
|
|
97,573
|
|
||||
Health and Welfare Benefits
(4)
|
79,493
|
|
|
40,489
|
|
|
12,141
|
|
|
—
|
|
||||
Total
|
$
|
2,190,061
|
|
|
$
|
1,890,835
|
|
|
$
|
501,874
|
|
|
$
|
97,573
|
|
(1)
|
Messrs. Sinclair’s and Fink’s and Ms. Dimpel’s values assume two times base salary plus one times target bonus multiplied by their allocation percentages in effect as of
December 31, 2015
. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(2)
|
Payment, if provided, will be paid at the end of the performance period based on actual performance. The values for Messrs. Sinclair and Fink and Ms. Dimpel reflect the allocated portion of their actual bonuses awarded under the AIP. For additional discussion of this program, read
Compensation Discussion and Analysis — Analysis of
2015
Compensation Actions — Performance-Based Annual Cash Incentives (Bonuses)
of Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
March 31, 2016
. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(3)
|
Reflects the in-the-money value of unvested stock options, the estimated current value of unvested performance units (based on performance to date) and the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of
December 31, 2015
. In the event of an involuntary termination, unvested performance units would be paid after the end of the applicable performance period, based on actual performance. All values reflect each named executive officer’s allocation percentage in effect as of
December 31, 2015
.
|
(4)
|
Messrs. Sinclair’s and Fink’s and Ms. Dimpel’s values represent 24 months of health and welfare benefit coverage. These amounts are present values determined in accordance with GAAP. These values reflect their allocation percentage in effect as of
December 31, 2015
. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Cash Severance
(1)
|
$
|
2,055,375
|
|
|
$
|
1,251,000
|
|
|
$
|
341,500
|
|
|
$
|
—
|
|
Pro-rata Bonus
(2)
|
371,250
|
|
|
297,000
|
|
|
80,750
|
|
|
—
|
|
||||
Accelerated Anadarko Equity Compensation
(3)
|
829,106
|
|
|
713,736
|
|
|
178,333
|
|
|
97,573
|
|
||||
Accelerated WGP Equity Compensation
(4)
|
165,519
|
|
|
92,685
|
|
|
—
|
|
|
—
|
|
||||
Supplemental Pension Benefits
(5)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Nonqualified Deferred Compensation
(6)
|
212,625
|
|
|
125,100
|
|
|
20,490
|
|
|
—
|
|
||||
Health and Welfare Benefits
(7)
|
133,546
|
|
|
40,489
|
|
|
12,141
|
|
|
—
|
|
||||
Total
|
$
|
3,767,421
|
|
|
$
|
2,520,010
|
|
|
$
|
633,214
|
|
|
$
|
97,573
|
|
(1)
|
Mr. Sinclair’s values and Mr. Fink’s and Ms. Dimpel’s values assume 2.9 times and two times, respectively, the sum of base salary plus the highest bonus paid in the past three years and reflect their allocation percentages in effect as of
December 31, 2015
, per the terms of their key employee change of control agreements with Anadarko. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(2)
|
Messrs. Sinclair’s and Fink’s and Ms. Dimpel’s values assume the full-year equivalent of their highest annual bonus allocated to us over the past three years. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(3)
|
Reflects the in-the-money value of unvested stock options, the value of unvested restricted stock shares and restricted stock units and the estimated current value of unvested performance units (based on performance to date) granted under Anadarko equity plans, all as of
December 31, 2015
. Upon a Change of Control, the value of unvested performance units would be calculated based on Anadarko’s total shareholder return performance and stock price at the time of the Change of Control and converted into restricted stock units of the surviving company. In the event of an involuntary not for cause termination or voluntary for good reason termination within two years following a Change of Control, the units will generally be paid on the first business day that is at least six months and one day following the separation from service. In the event of an involuntary not for cause or voluntary for good reason termination that is more than two years following a Change of Control, the units will be paid at the end of the original performance period. All values reflect each named executive officer’s allocation percentage in effect as of
December 31, 2015
.
|
(4)
|
Reflects the value of unvested WGP LTIP phantom units based on the applicable closing common unit price of
$36.29
on
December 31, 2015
. All values reflect each named executive officer’s allocation percentage in effect as of
December 31, 2015
.
|
(5)
|
Under the terms of their change of control agreements, Messrs. Sinclair and Fink and Ms. Dimpel would receive a special retirement benefit enhancement that is equivalent to the additional supplemental pension benefits that would have accrued under Anadarko’s retirement plan assuming they were eligible for subsidized early retirement benefits and include additional special pension credits. The value of this benefit has not been included in this table as Anadarko does not allocate expense to the partnership for distribution of these benefits. If Anadarko were to allocate this expense to the Partnership, assuming their allocation percentages in effect as of
December 31, 2015
, the expense would be as follows: Mr. Sinclair—$194,089, Mr. Fink—$88,455 and Ms. Dimpel—$197,845.
|
(6)
|
Mr. Sinclair’s values and Mr. Fink’s and Ms. Dimpel’s values reflect an additional three years and two years, respectively, of employer contributions into the savings restoration plan at their current contribution rate to the Plan and are based on their allocation percentages in effect as of
December 31, 2015
, per the terms of their key employee change of control agreements with Anadarko. No value has been disclosed for Mr. Peacock as he is not eligible for this additional benefit.
|
(7)
|
Mr. Sinclair’s values and Mr. Fink’s and Ms. Dimpel’s values represent 36 months and 24 months, respectively, of health and welfare benefit coverage. All amounts are present values determined in accordance with GAAP and reflect their allocation percentages in effect as of
December 31, 2015
. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Cash Severance
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accelerated Anadarko Equity Compensation
(1)
|
829,106
|
|
|
713,736
|
|
|
178,333
|
|
|
97,573
|
|
||||
Health and Welfare Benefits
(2)
|
90,895
|
|
|
130,075
|
|
|
23,270
|
|
|
51,219
|
|
||||
Total
|
$
|
920,001
|
|
|
$
|
843,811
|
|
|
$
|
201,603
|
|
|
$
|
148,792
|
|
(1)
|
Reflects the in-the-money value of unvested stock options, the value of unvested restricted stock shares and restricted stock units and the estimated current value of unvested performance units (based on performance to date) granted under Anadarko equity plans, all as of
December 31, 2015
. In the event of a termination as a result of disability, performance units would be paid after the end of the applicable performance period, based on actual performance. All values reflect each named executive officer’s allocation percentage in effect as of
December 31, 2015
.
|
(2)
|
Values reflect the continuation of additional death benefit coverage provided to certain employees of Anadarko until age 65. All amounts are present values determined in accordance with GAAP and reflect each named executive officer’s allocation percentage in effect as of
December 31, 2015
.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Cash Severance
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accelerated Anadarko Equity Compensation
(1)
|
974,467
|
|
|
830,036
|
|
|
205,008
|
|
|
97,573
|
|
||||
Life Insurance Proceeds
(2)
|
1,162,791
|
|
|
1,131,783
|
|
|
310,078
|
|
|
447,674
|
|
||||
Total
|
$
|
2,137,258
|
|
|
$
|
1,961,819
|
|
|
$
|
515,086
|
|
|
$
|
545,247
|
|
(1)
|
Reflects the in-the-money value of unvested stock options, the target value of unvested performance units, and the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of
December 31, 2015
. All values reflect each named executive officer’s allocation percentage in effect as of
December 31, 2015
.
|
(2)
|
Values include amounts payable under additional death benefits provided to certain employees of Anadarko. These liabilities are not insured, but are self-funded by Anadarko. Proceeds are not exempt from federal taxes. Values shown include an additional tax gross-up amount to equate benefits with non-taxable life insurance proceeds. Values are based on each named executive officer’s allocation percentage in effect as of
December 31, 2015
, and exclude death benefit proceeds from programs available to all employees.
|
•
|
an annual retainer of $90,000 for each board member;
|
•
|
an annual retainer of $2,000 for each member of the Audit Committee, or $22,000 for the Committee chair;
|
•
|
an annual retainer of $2,000 for each member of the Special Committee, or $22,000 for the Committee chair;
|
•
|
a fee of $2,000 for each board meeting attended;
|
•
|
a fee of $2,000 for each committee meeting attended; and
|
•
|
annual grants of phantom units with a value of approximately $90,000 on the date of grant, all of which vest 100% on the first anniversary of the date of grant (with vesting to be accelerated upon a change of control of our general partner or Anadarko). The non-employee directors received such a grant of phantom units on May 13,
2015
.
|
Name
|
|
Fees Earned or Paid in Cash
|
|
Stock Awards
(1)
|
|
Option Awards
|
|
Non-Equity Incentive Plan Compensation
|
|
All Other Compensation
|
|
Total
|
||||||||||||
Steven D. Arnold
|
|
$
|
126,000
|
|
|
$
|
90,037
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
216,037
|
|
Milton Carroll
|
|
136,000
|
|
|
90,037
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
226,037
|
|
||||||
James R. Crane
|
|
118,000
|
|
|
90,037
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
208,037
|
|
||||||
David J. Tudor
|
|
130,000
|
|
|
90,037
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
220,037
|
|
(1)
|
The amounts included in the Stock Awards column represent the grant date fair value of non-option awards made to directors in
2015
, computed in accordance with FASB ASC Topic 718. For a discussion of valuation assumptions, see
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K. As of
December 31, 2015
, each of the non-employee directors had 1,303 outstanding phantom units.
|
Name
|
|
Grant Date
|
|
Phantom Units (#)
|
|
Grant Date Fair Value of Stock and Option Awards ($)
(1)
|
||
Steven D. Arnold
|
|
May 13
|
|
1,303
|
|
|
90,037
|
|
Milton Carroll
|
|
May 13
|
|
1,303
|
|
|
90,037
|
|
James R. Crane
|
|
May 13
|
|
1,303
|
|
|
90,037
|
|
David J. Tudor
|
|
May 13
|
|
1,303
|
|
|
90,037
|
|
(1)
|
The amounts included in the Grant Date Fair Value of Stock and Option Awards column represent the grant date fair value of the awards made to non-employee directors in
2015
computed in accordance with FASB ASC Topic 718. The value ultimately realized by a director upon the actual vesting of the award(s) may or may not be equal to the determined value.
|
•
|
each member of the Board of Directors of our general partner;
|
•
|
each named executive officer of our general partner;
|
•
|
all directors and officers of our general partner as a group; and
|
•
|
Anadarko and its affiliates.
|
|
|
WES
|
|
WGP
|
||||||
Name and Address of Beneficial Owner
(1)
|
|
Common
Units
Beneficially Owned
|
|
Percentage of
Common Units
Beneficially
Owned
|
|
Common
Units
Beneficially
Owned
|
|
Percentage of
Common Units
Beneficially
Owned
|
||
Anadarko Petroleum Corporation
(2)
|
|
50,053,824
|
|
|
38.93%
|
|
191,087,365
|
|
|
87.29%
|
Robert G. Gwin
|
|
10,000
|
|
|
*
|
|
200,000
|
|
|
*
|
Donald R. Sinclair
(3)
|
|
100,664
|
|
|
*
|
|
307,548
|
|
|
*
|
Benjamin M. Fink
(3)
|
|
2,213
|
|
|
*
|
|
16,622
|
|
|
*
|
Jacqueline A. Dimpel
|
|
—
|
|
|
*
|
|
100
|
|
|
*
|
Philip H. Peacock
|
|
—
|
|
|
*
|
|
7,500
|
|
|
*
|
Steven D. Arnold
(3)
|
|
33,014
|
|
|
*
|
|
7,500
|
|
|
*
|
Milton Carroll
(3) (4)
|
|
5,419
|
|
|
*
|
|
—
|
|
|
*
|
James R. Crane
(3) (4)
|
|
505,060
|
|
|
*
|
|
—
|
|
|
*
|
Darrell E. Hollek
|
|
—
|
|
|
*
|
|
7,500
|
|
|
*
|
Robert K. Reeves
|
|
9,000
|
|
|
*
|
|
9,000
|
|
|
*
|
David J. Tudor
(3)
|
|
11,595
|
|
|
*
|
|
5,454
|
|
|
*
|
All directors and executive officers
as a group (11 persons)
(3) (4)
|
|
676,965
|
|
|
*
|
|
561,224
|
|
|
*
|
*
|
Less than 1%
|
(1)
|
The address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.
|
(2)
|
WGP held
49,296,205
common units and other subsidiaries of Anadarko, AMM and AMH, collectively held
757,619
common units. Anadarko is the ultimate parent company of Western Gas Resources, Inc. (“WGRI”), AMM, AMH and WGP GP and may, therefore, be deemed to beneficially own the units held by such parties. Anadarko, through AMH, also held
11,735,446
Class C units of the Partnership.
|
(3)
|
Does not include (a)
1,303
unvested phantom units that were granted to each of Messrs. Carroll, Crane, Tudor, and Arnold under the WES LTIP, and (b) an aggregate
8,919
unvested phantom units that were previously granted to Messrs. Sinclair and Fink under the WGP LTIP. Phantom units granted to the independent directors of WES vest 100% on the first anniversary of the date of the grant, and Mr. Sinclair’s and Mr. Fink’s phantom unit awards vest pro-rata over three years. Each vested phantom unit entitles the holder to receive a common unit or, in the discretion of our general partner’s Board of Directors, cash equal to the fair market value of a common unit. Holders of phantom units are entitled to distribution equivalents on a current basis. Holders of phantom units have no voting rights until such time as the phantom units become vested and common units are issued to such holders.
|
(4)
|
Includes 2,000 and 495,601 WES units held by Messrs. Carroll and Crane, respectively.
|
Name and Address of Beneficial Owner
(1)
|
|
Shares of
Common Stock
Owned Directly
or Indirectly
(
2)
|
|
Shares
Underlying
Options
Exercisable
Within 60 Days
(2)
|
|
Total Shares of
Common Stock
Beneficially
Owned
(2)
|
|
Percentage of
Total Shares of
Common Stock
Beneficially
Owned
(2)
|
|||
Robert G. Gwin
(3)
|
|
101,550
|
|
|
335,490
|
|
|
437,040
|
|
|
*
|
Donald R. Sinclair
(3)
|
|
17,694
|
|
|
42,264
|
|
|
59,958
|
|
|
*
|
Benjamin M. Fink
(3)
(4)
|
|
8,407
|
|
|
21,496
|
|
|
29,903
|
|
|
*
|
Jacqueline A. Dimpel
(3) (4)
|
|
8,815
|
|
|
13,188
|
|
|
22,003
|
|
|
*
|
Philip H. Peacock
(4)
|
|
4,843
|
|
|
—
|
|
|
4,843
|
|
|
*
|
Steven D. Arnold
|
|
13,600
|
|
|
—
|
|
|
13,600
|
|
|
*
|
Milton Carroll
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
James R. Crane
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Darrell E. Hollek
(3)
|
|
17,672
|
|
|
96,351
|
|
|
114,023
|
|
|
*
|
Robert K. Reeves
(3)
|
|
111,545
|
|
|
210,541
|
|
|
322,086
|
|
|
*
|
David J. Tudor
|
|
—
|
|
|
—
|
|
|
—
|
|
|
*
|
All directors and executive officers
as a group (11 persons)
(3) (4)
|
|
284,126
|
|
|
719,330
|
|
|
1,003,456
|
|
|
*
|
*
|
Less than 1%
|
(1)
|
The address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.
|
(2)
|
As of January 31,
2016
, there were 508.4 million shares of Anadarko common stock issued and outstanding.
|
(3)
|
Does not include unvested restricted stock units of Anadarko held by the following individuals in the amounts indicated: Robert G. Gwin—27,963; Donald R. Sinclair—10,535; Benjamin M. Fink—7,000; Jacqueline A. Dimpel—5,468; Darrell E. Hollek—39,444; Robert K. Reeves—22,002; and a total of 112,412 unvested restricted stock units are held by the directors and executive officers as a group. Restricted stock units typically vest equally over three years beginning on the first anniversary of the date of grant, and upon vesting are payable in Anadarko common stock, subject to applicable tax withholding. Holders of restricted stock units receive dividend equivalents on the units, but do not have voting rights. Generally, a holder will forfeit any unvested restricted units if he or she terminates voluntarily or is terminated for cause prior to the vesting date. Holders of restricted stock units have the ability to defer such awards.
|
(4)
|
Includes unvested shares of restricted common stock of Anadarko held by the following individuals in the amounts indicated: Benjamin M. Fink—1,087; Jacqueline A. Dimpel—644; Philip H. Peacock—4,017; and a total of 5,748 unvested shares of restricted common stock are held by the directors and executive officers as a group. Restricted stock awards typically vest equally over three years beginning on the first anniversary of the date of grant. Holders of restricted stock receive dividends on the shares and also have voting rights. Generally, a holder of restricted stock will forfeit any unvested restricted shares if he or she terminates voluntarily or is terminated for cause prior to the vesting date.
|
Title of Class
|
|
Name and Address of Beneficial Owner
|
|
Amount and
Nature
of Beneficial
Ownership
|
|
Percent of Class
|
Common Units
|
|
Tortoise Capital Advisors, L.L.C.
11550 Ash Street
Suite 300
Leawood, KS 66211
|
|
11,086,053
(1)
|
|
8.60%
|
Common Units
|
|
Kayne Anderson Capital Advisors, L.P.
1800 Avenue of the Stars Third Floor Los Angeles, CA 90067 |
|
9,465,850
(2)
|
|
7.36%
|
(1)
|
Based upon its Schedule 13G/A filed February 10,
2016
, with the SEC with respect to Partnership securities held as of
December 31, 2015
, Tortoise Capital Advisors, L.L.C. has shared voting power as to
9,983,215
common units and shared dispositive power as to
10,938,854
common units.
|
(2)
|
Based upon its Schedule 13G/A filed January 27,
2016
, with the SEC with respect to Partnership securities held as of
December 31, 2015
, Kayne Anderson Capital Advisors, L.P. has shared voting and dispositive power as to
9,465,850
common units.
|
Plan Category
|
|
(a)
Number of
Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights
|
|
(b)
Weighted-Average
Exercise Price of
Outstanding
Options, Warrants
and Rights
|
|
(c)
Number of Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
(Excluding Securities
Reflected in Column(a))
|
|||
Equity compensation plans approved by security holders
|
|
—
|
|
|
—
|
|
|
—
|
|
Equity compensation plans not approved by security holders
(1)
|
|
5,477
|
|
|
—
(2)
|
|
|
2,128,015
|
|
Total
|
|
5,477
|
|
|
—
|
|
|
2,128,015
|
|
(1)
|
The Board of Directors of our general partner adopted the WES LTIP in connection with the IPO of our common units.
|
(2)
|
Phantom units constitute the only rights outstanding under the WES LTIP. Each phantom unit that may be settled in common units entitles the holder to receive, upon vesting, one common unit with respect to each phantom unit, without payment of any cash. Accordingly, there is no reportable weighted-average exercise price.
|
Formation stage
|
|
|
|
|
|
The consideration received by Anadarko for the contribution of the assets and liabilities to us
|
|
5,725,431 common units; 26,536,306 subordinated units; 1,083,115 general partner units, and our IDRs.
|
|
|
|
Operational stage
|
|
|
|
|
|
Distributions of available cash to our general partner, WGP and other subsidiaries of Anadarko
|
|
We will generally make cash distributions of 98.2% to our unitholders pro rata, including WGP and other subsidiaries of Anadarko as the holders of 49,296,205 common units and 757,619 common units, respectively, and 1.8% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 49.8% of the distributions above the highest target distribution level. As of December 31, 2015, the general partner was entitled to a maximum distribution sharing percentage of 49.8%, which includes distributions paid on its 1.8% general partner interest and the 48.0% IDR maximum distribution sharing percentage. See
Note 3
—
Partnership Distributions
and
Note 4—Equity and Partners'
Capital
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K.
|
|
|
|
Distributions of additional Class C units
|
|
In connection with the closing of the DBM acquisition in November 2014, we issued 10,913,853 Class C units. Class C units receive quarterly distributions at a rate equivalent to our common units.
As of February 22, 2016,
we have issued 821,593 PIK Class C units as quarterly distributions. For a further discussion of the Class C units, refer to
Class C Unit Issuance
below.
|
|
|
|
Payments to our general partner and its affiliates
|
|
Our general partner and its affiliates are entitled to reimbursement for expenses incurred on our behalf, including salaries and employee benefit costs for employees who provide services to us, and all other necessary or appropriate expenses allocable to us or reasonably incurred by our general partner and its affiliates in connection with operating our business. The partnership agreement provides that our general partner determines in good faith the amount of such expenses that are allocable to us.
|
|
|
|
Withdrawal or removal of our general partner
|
|
If our general partner withdraws or is removed, its general partner interest and its IDRs will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
|
|
|
|
Liquidation stage
|
|
|
|
|
|
Liquidation
|
|
Upon our liquidation, our partners, including our general partner, WGP and other subsidiaries of Anadarko, will be entitled to receive liquidating distributions according to their respective capital account balances.
|
•
|
Anadarko’s obligation to indemnify us for certain liabilities and our obligation to indemnify Anadarko for certain liabilities;
|
•
|
our obligation to reimburse Anadarko for expenses incurred or payments made on our behalf in conjunction with Anadarko’s provision of general and administrative services to us, including salary and benefits of Anadarko personnel, our public company expenses, general and administrative expenses and salaries and benefits of our executive management who are employees of Anadarko (see
Administrative services and reimbursement
below for details regarding certain agreements for amounts reimbursed in
2015
); and
|
•
|
our obligation to reimburse Anadarko for all insurance coverage expenses it incurs or payments it makes with respect to our assets.
|
thousands
|
|
Year Ended
December 31, 2015 |
||
Reimbursement of general and administrative expenses
|
|
$
|
22,896
|
|
Reimbursement of public company expenses
|
|
8,950
|
|
|
Total reimbursement
|
|
$
|
31,846
|
|
•
|
Chipeta’s members will be required from time to time to make capital contributions to Chipeta to the extent approved by the members in connection with Chipeta’s annual budget;
|
•
|
Chipeta will distribute available cash, as defined in the Chipeta LLC agreement, if any, to its members quarterly in accordance with those members’ membership interests; and
|
•
|
Chipeta’s membership interests are subject to significant restrictions on transfer.
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||
|
|
2015
|
|
2014
|
|
2013
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||
thousands
|
|
Purchases
|
|
Sales
|
||||||||||||||||||||
Cash consideration
|
|
$
|
12,664
|
|
|
$
|
22,943
|
|
|
$
|
11,211
|
|
|
$
|
925
|
|
|
$
|
—
|
|
|
$
|
85
|
|
Net carrying value
|
|
7,944
|
|
|
12,210
|
|
|
5,309
|
|
|
972
|
|
|
—
|
|
|
38
|
|
||||||
Partners’ capital adjustment
|
|
$
|
4,720
|
|
|
$
|
10,733
|
|
|
$
|
5,902
|
|
|
$
|
(47
|
)
|
|
$
|
—
|
|
|
$
|
47
|
|
|
|
Year ended December 31,
|
||||||||||
thousands
|
|
2015
|
|
2014
|
|
2013
|
||||||
Revenues and other
(1)
|
|
$
|
1,029,922
|
|
|
$
|
1,053,935
|
|
|
$
|
844,203
|
|
Equity income, net
(1)
|
|
71,251
|
|
|
57,836
|
|
|
22,948
|
|
|||
Cost of product
(1)
|
|
167,420
|
|
|
127,906
|
|
|
136,570
|
|
|||
Operation and maintenance
(2)
|
|
67,119
|
|
|
62,306
|
|
|
59,698
|
|
|||
General and administrative
(3)
|
|
30,692
|
|
|
28,970
|
|
|
24,956
|
|
|||
Operating expenses
|
|
265,231
|
|
|
219,182
|
|
|
221,224
|
|
|||
Interest income
(4)
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
(5)
|
|
14,398
|
|
|
—
|
|
|
—
|
|
|||
Distributions to unitholders
(6)
|
|
314,200
|
|
|
234,024
|
|
|
169,150
|
|
|||
Above-market component of swap extensions with Anadarko
(7)
|
|
18,449
|
|
|
—
|
|
|
—
|
|
(1)
|
Represents amounts earned or incurred on and subsequent to the date of acquisition of our assets, as well as amounts earned or incurred by Anadarko on a historical basis related to our assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.
|
(2)
|
Represents expenses incurred on and subsequent to the date of the acquisition of our assets, as well as expenses incurred by Anadarko on a historical basis related to our assets prior to the acquisition of such assets.
|
(3)
|
Represents general and administrative expense incurred on and subsequent to the date of the acquisition of our assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of our assets by us. These amounts include equity-based compensation expense allocated to us by Anadarko. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K.
|
(4)
|
Represents interest income recognized on the note receivable from Anadarko.
|
(5)
|
For the year ended December 31, 2015, includes accretion expense recognized on the Deferred purchase price obligation - Anadarko for the acquisition of DBJV. See
Note 2—Acquisitions and Divestitures
and
Note 12—Debt and Interest Expense
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K
.
|
(6)
|
Represents distributions paid under the partnership agreement. See
Note 3—Partnership Distributions
and
Note 4—Equity and Partners’ Capital
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K.
|
(7)
|
See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K for more information.
|
•
|
approved by the Special Committee of our general partner, although our general partner is not obligated to seek such approval;
|
•
|
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 among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
|
thousands
|
|
2015
|
|
2014
|
||||
Audit fees
|
|
$
|
1,309
|
|
|
$
|
1,227
|
|
Audit-related fees
|
|
423
|
|
|
491
|
|
||
Total
|
|
$
|
1,732
|
|
|
$
|
1,718
|
|
Exhibit
Number
|
|
Description
|
2.1#
|
|
Contribution, Conveyance and Assumption Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, Anadarko Petroleum Corporation, WGR Holdings, LLC, Western Gas Resources, Inc., WGR Asset Holding Company LLC, Western Gas Operating, LLC and WGR Operating, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
2.2#
|
|
Contribution Agreement, dated as of November 11, 2008, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on November 13, 2008, File No. 001-34046).
|
2.3#
|
|
Contribution Agreement, dated as of July 10, 2009, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, Anadarko Uintah Midstream, LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
|
2.4#
|
|
Contribution Agreement, dated as of January 29, 2010 by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, Mountain Gas Resources LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010 File No. 001-34046).
|
2.5#
|
|
Contribution Agreement, dated as of July 30, 2010, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046).
|
2.6#
|
|
Purchase and Sale Agreement, dated as of January 14, 2011, by and among Western Gas Partners, LP, Kerr-McGee Gathering LLC and Encana Oil & Gas (USA) Inc. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 18, 2011 File No. 001-34046).
|
2.7#
|
|
Contribution Agreement, dated as of December 15, 2011, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 15, 2011, File No. 001-34046).
|
2.8#
|
|
Contribution Agreement, dated as of February 27, 2013, by and among Anadarko Marcellus Midstream, L.L.C., Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP, Anadarko Petroleum Corporation and Anadarko E&P Onshore LLC (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
|
Exhibit
Number
|
|
Description
|
2.9#
|
|
Contribution Agreement, dated as of February 27, 2014, by and among WGR Asset Holding Company LLC, APC Midstream Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 2.9 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 28, 2014, File No. 001-34046).
|
2.10#
|
|
Agreement and Plan of Merger, dated October 28, 2014, by and among Western Gas Partners, LP, Maguire Midstream LLC and Nuevo Midstream, LLC (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on October 28, 2014, File No. 001-34046).
|
2.11#
|
|
Purchase and Sale Agreement, dated as of March 2, 2015, by and among WGR Asset Holding Company LLC, Delaware Basin Midstream, LLC, Western Gas Partners, LP, and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 3, 2015, File No. 001-34046).
|
3.1
|
|
Certificate of Limited Partnership of Western Gas Partners, LP (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
|
3.2
|
|
First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated May 14, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
3.3
|
|
Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated December 19, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 24, 2008, File No. 001-34046).
|
3.4
|
|
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated as of April 15, 2009 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on April 20, 2009, File No. 001-34046).
|
3.5
|
|
Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated July 22, 2009 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
|
3.6
|
|
Amendment No. 4 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated January 29, 2010 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010, File No. 001-34046).
|
3.7
|
|
Amendment No. 5 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated August 2, 2010 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046).
|
3.8
|
|
Amendment No. 6 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated July 8, 2011 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 8, 2011, File No. 001-34046).
|
3.9
|
|
Amendment No. 7 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated January 13, 2012 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 17, 2012, File No. 001-34046).
|
3.10
|
|
Amendment No. 8 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated August 1, 2012 (incorporated by reference to Exhibit 3.10 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on August 2, 2012, File No. 001-34046).
|
3.11
|
|
Amendment No. 9 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated December 12, 2012 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-34046).
|
3.12
|
|
Amendment No. 10 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 1, 2013 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
|
3.13
|
|
Amendment No. 11 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 3, 2014 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2014, File No. 001-34046).
|
3.14
|
|
Amendment No. 12 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated November 25, 2014 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on November 25, 2014, File No. 001-34046).
|
Exhibit
Number
|
|
Description
|
3.15
|
|
Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
|
3.16
|
|
Second Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated December 12, 2012 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-34046).
|
4.1
|
|
Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
|
4.2
|
|
Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
|
4.3
|
|
First Supplemental Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
|
4.4
|
|
Form of 5.375% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
|
4.5
|
|
Fifth Supplemental Indenture, dated as of August 14, 2013, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 14, 2013, File No. 001-34046).
|
4.6
|
|
Form of 4.000% Senior Notes due 2022 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
|
4.7
|
|
Form of 2.600% Senior Notes due 2018 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 14, 2013, File No. 001-34046).
|
4.8
|
|
Sixth Supplemental Indenture, dated as of March 20, 2014, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
|
4.9
|
|
Form of 5.450% Senior Notes due 2044 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
|
4.10
|
|
Seventh Supplemental Indenture, dated as of June 4, 2015, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).
|
4.11
|
|
Form of 3.950% Senior Notes due 2025 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).
|
10.1
|
|
Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC and Anadarko Petroleum Corporation, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.2
|
|
Amendment No. 1 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of December 19, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 24, 2008, File No. 001-34046).
|
10.3
|
|
Amendment No. 2 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of July 22, 2009 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
|
10.4
|
|
Amendment No. 3 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of December 31, 2009 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 7, 2010, File No. 001-34046).
|
10.5
|
|
Amendment No. 4 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of January 29, 2010 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010, File No. 001-34046).
|
Exhibit
Number
|
|
Description
|
10.6
|
|
Amendment No. 5 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of August 2, 2010 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046).
|
10.7
|
|
Services And Secondment Agreement between Western Gas Holdings, LLC and Anadarko Petroleum Corporation dated May 14, 2008 (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.8*
|
|
Amendment No. 1 to Services And Secondment Agreement between Western Gas Holdings, LLC and Anadarko Petroleum Corporation dated December 10, 2015.
|
10.9
|
|
Tax Sharing Agreement by and among Anadarko Petroleum Corporation and Western Gas Partners, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.5 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.10
|
|
Anadarko Petroleum Corporation Fixed Rate Note due 2038 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.11
|
|
Form of Commodity Price Swap Agreement (filed as Exhibit 10.3 to the Partnership’s Form 10-Q for the quarter ended March 31, 2010).
|
10.12‡
|
|
Form of Indemnification Agreement by and between Western Gas Holdings, LLC, its Officers and Directors (incorporated by reference to Exhibit 10.10 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
|
10.13‡
|
|
Western Gas Partners, LP 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.13 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
|
10.14‡
|
|
Form of Award Agreement under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.9 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.15†
|
|
Amended and Restated Limited Liability Company Agreement of Chipeta Processing LLC effective July 23, 2009 (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on November 12, 2009, File No. 001-34046).
|
10.16
|
|
Second Amended and Restated Revolving Credit Agreement, dated as of February 26, 2014, among Western Gas Partners, LP, Wells Fargo Bank National Association, as the administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.15 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 28, 2014, File No. 001-34046).
|
10.17
|
|
Indemnification Agreement, dated March 1, 2013, between Western Gas Holdings, LLC and Anadarko E&P Onshore LLC (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
|
10.18
|
|
Third Amended and Restated Indemnification Agreement, dated March 1, 2013, between Western Gas Holdings, LLC and Western Gas Resources, Inc. (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
|
10.19
|
|
Assignment of Indemnification Agreement, dated April 1, 2013, between Anadarko USH2 LLC and Anadarko E&P Onshore LLC (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on August 1, 2013, File No. 001-34046).
|
10.20
|
|
AMH Indemnification Agreement, dated March 3, 2014, between Western Gas Holdings, LLC and APC Midstream Holdings, LLC (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2014, File No. 001-34046).
|
10.21
|
|
First Amendment to the Third Amended and Restated Indemnification Agreement, dated March 3, 2014, between Western Gas Holdings, LLC and Western Gas Resources, Inc. (incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2014, File No. 001-34046).
|
10.22
|
|
USH2 Indemnification Agreement, dated March 3, 2014, Western Gas Holdings, LLC and USH2 LLC (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2014, File No. 001-34046).
|
10.23
|
|
Unit Purchase Agreement, dated October 28, 2014, by and among Western Gas Partners, LP, APC Midstream Holdings, LLC and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on October 28, 2014, File No. 001-34046).
|
|
|
|
Exhibit
Number
|
|
Description
|
10.24†
|
|
Gas Gathering Agreement effective July 1, 2010 between Kerr-McGee Gathering LLC and Kerr-McGee Oil & Gas Onshore LP, as amended by Amendment No. 1 dated August 4, 2011, Amendment No. 2 dated December 3, 2012, Amendment No. 3 dated November 19, 2013 and Amendment No. 4 dated June 2, 2014 (incorporated by reference to Exhibit 10.23 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 26, 2015, File No. 001-34046).
|
12.1*
|
|
Ratio of Earnings to Fixed Charges.
|
21.1*
|
|
List of Subsidiaries of Western Gas Partners, LP.
|
23.1*
|
|
Consent of KPMG LLP.
|
31.1*
|
|
Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
31.2*
|
|
Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
32.1**
|
|
Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
101.INS*
|
|
XBRL Instance Document
|
101.SCH*
|
|
XBRL Schema Document
|
101.CAL*
|
|
XBRL Calculation Linkbase Document
|
101.DEF*
|
|
XBRL Definition Linkbase Document
|
101.LAB*
|
|
XBRL Label Linkbase Document
|
101.PRE*
|
|
XBRL Presentation Linkbase Document
|
*
|
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 schedule to the Securities and Exchange Commission upon request.
|
†
|
Portions of this exhibit, which was previously filed with the Securities and Exchange Commission, were omitted pursuant to a request for confidential treatment. The omitted portions were filed separately with the Securities and Exchange Commission.
|
‡
|
Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.
|
|
WESTERN GAS PARTNERS, LP
|
|
|
February 25, 2016
|
|
|
|
|
/s/ Benjamin M. Fink
|
|
Benjamin M. Fink
Senior Vice President, Chief Financial Officer and Treasurer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
Signature
|
Title (Position with Western Gas Holdings, LLC)
|
|
|
/s/ Robert G. Gwin
|
Chairman and Director
|
Robert G. Gwin
|
|
|
|
/s/ Donald R. Sinclair
|
President, Chief Executive Officer and Director
|
Donald R. Sinclair
|
(Principal Executive Officer)
|
|
|
/s/ Benjamin M. Fink
|
Senior Vice President, Chief Financial Officer and Treasurer
|
Benjamin M. Fink
|
(Principal Financial and Accounting Officer)
|
|
|
/s/ Darrell E. Hollek
|
Director
|
Darrell E. Hollek
|
|
|
|
/s/ Robert K. Reeves
|
Director
|
Robert K. Reeves
|
|
|
|
/s/ Steven D. Arnold
|
Director
|
Steven D. Arnold
|
|
|
|
/s/ Milton Carroll
|
Director
|
Milton Carroll
|
|
|
|
/s/ James R. Crane
|
Director
|
James R. Crane
|
|
|
|
/s/ David J. Tudor
|
Director
|
David J. Tudor
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
thousands
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) before income taxes
|
|
$
|
(60,057
|
)
|
|
$
|
419,526
|
|
|
$
|
294,199
|
|
|
$
|
173,329
|
|
|
$
|
238,827
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges
|
|
122,456
|
|
|
87,102
|
|
|
64,120
|
|
|
48,517
|
|
|
31,478
|
|
|||||
Distributions from equity investees
|
|
98,298
|
|
|
81,022
|
|
|
22,136
|
|
|
20,660
|
|
|
15,999
|
|
|||||
Amortization of capitalized interest
|
|
2,197
|
|
|
1,695
|
|
|
821
|
|
|
481
|
|
|
294
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Equity income, net
|
|
71,251
|
|
|
57,836
|
|
|
22,948
|
|
|
16,042
|
|
|
11,261
|
|
|||||
Capitalized interest
|
|
8,318
|
|
|
9,832
|
|
|
11,945
|
|
|
6,196
|
|
|
420
|
|
|||||
Net income before taxes attributable to noncontrolling interests
|
|
10,101
|
|
|
14,025
|
|
|
10,816
|
|
|
14,890
|
|
|
14,103
|
|
|||||
Earnings
|
|
$
|
73,224
|
|
|
$
|
507,652
|
|
|
$
|
335,567
|
|
|
$
|
205,859
|
|
|
$
|
260,814
|
|
Fixed charges:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, including capitalized interest
|
|
$
|
122,190
|
|
|
$
|
86,598
|
|
|
$
|
63,742
|
|
|
$
|
48,256
|
|
|
$
|
31,221
|
|
Interest component of rent expense
|
|
266
|
|
|
504
|
|
|
378
|
|
|
261
|
|
|
257
|
|
|||||
Fixed charges
|
|
$
|
122,456
|
|
|
$
|
87,102
|
|
|
$
|
64,120
|
|
|
$
|
48,517
|
|
|
$
|
31,478
|
|
Ratio of earnings to fixed charges
|
|
*
|
|
|
5.8x
|
|
|
5.2x
|
|
|
4.2x
|
|
|
8.3x
|
|
*
|
As a result of the Partnership’s net loss in 2015, earnings did not cover total fixed charges by $49.2 million for 2015.
|
1.
|
I have reviewed this
annual
report on Form
10-K
of Western Gas Partners, LP (the “registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
/s/ Donald R. Sinclair
|
|
Donald R. Sinclair
President and Chief Executive Officer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
1.
|
I have reviewed this
annual
report on Form
10-K
of Western Gas Partners, LP (the “registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
/s/ Benjamin M. Fink
|
|
Benjamin M. Fink
Senior Vice President, Chief Financial Officer and Treasurer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
(1)
|
the
Annual
Report on Form
10-K
of the Partnership for the period ending
December 31, 2015
, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
|
February 25, 2016
|
|
|
|
|
|
|
|
/s/ Donald R. Sinclair
|
|
|
Donald R. Sinclair
|
|
|
President and Chief Executive Officer
|
|
|
Western Gas Holdings, LLC
|
|
|
(as general partner of Western Gas Partners, LP)
|
|
|
|
February 25, 2016
|
|
|
|
|
|
|
|
/s/ Benjamin M. Fink
|
|
|
Benjamin M. Fink
|
|
|
Senior Vice President, Chief Financial Officer and Treasurer
|
|
|
Western Gas Holdings, LLC
|
|
|
(as general partner of Western Gas Partners, LP)
|