þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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¨
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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
þ
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Accelerated filer
¨
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Non-accelerated filer
¨
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Smaller reporting company
¨
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Emerging growth 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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16.
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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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Gathering systems
(1)
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12
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3
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3
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2
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Treating facilities
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19
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3
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—
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3
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Natural gas processing plants/trains
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20
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4
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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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5
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—
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—
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—
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Oil pipelines
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—
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1
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—
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1
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(1)
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Includes the DBM water systems.
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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)
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Processing, Treating or Disposal Capacity (MBbls/d)
(1)
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Average Gathering, Processing, Treating and Transportation Throughput (MMcf/d)
(2)
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Average Gathering, Treating, Transportation and Disposal Throughput (MBbls/d)
(3)
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Rocky Mountains
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Gathering, Processing and Treating
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7,414
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4,665
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515,032
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3,127
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14
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2,095
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—
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Transportation
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1,601
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72
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40,334
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—
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—
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87
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23
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Texas / New Mexico
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Gathering, Processing, Treating and Disposal
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2,155
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954
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516,149
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1,275
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374
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1,261
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106
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Transportation
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1,195
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16
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39,748
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—
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—
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—
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72
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North-central Pennsylvania
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Gathering
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144
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49
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6,900
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—
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—
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237
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—
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Total
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12,509
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5,756
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1,118,163
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4,402
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388
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3,680
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201
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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. Includes horsepower associated with liquid pump stations.
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(2)
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Includes 100% of Chipeta throughput, 50% of Newcastle throughput, 50.1% of Springfield gas gathering throughput, 22% of Rendezvous throughput and 14.81% of Fort Union throughput.
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(3)
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Consists of throughput on the Chipeta NGL pipeline, an NGL line at the Brasada complex and at the DBM water systems, a 50.1% share of average Springfield oil gathering throughput, a 10% share of average White Cliffs throughput, a 25% share of average Mont Belvieu JV throughput, a 20% share of average TEG and TEP throughput and a 33.33% share of average FRP throughput. See
Properties
below for further descriptions of these systems.
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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 infrastructure, operating expertise and customer relationships 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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Pursuing accretive acquisitions.
We expect to continue to pursue accretive acquisitions of midstream assets from Anadarko and third parties.
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•
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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 our accretion and overall return.
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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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Affiliation with Anadarko.
We believe Anadarko is motivated to promote and support the successful execution of our business plan and utilize its relationships within the energy industry and the strength of its asset portfolio to pursue projects that help to enhance the value of our business. This includes the ability of Anadarko to secure equity investment opportunities for us in connection with the commitments it makes to other midstream companies. See
Our Relationship with Anadarko Petroleum Corporation
below.
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Commodity price and volumetric risk mitigation.
We believe our cash flows are protected from fluctuations caused by commodity price volatility due to (i) the approximately
94%
of our Adjusted gross margin attributable 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,
2017
,
96%
of our Adjusted 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. See
How We Evaluate Our Operations
under Part II, Item 7 of this Form 10-K. On
December 20, 2017
, we renewed our commodity price swap agreements with Anadarko for the DJ Basin complex and the MGR assets through December 31, 2018. 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 structures and/or minimum volume commitments. For the year ended December 31,
2017
, and excluding throughput measured in barrels, 62% of our throughput was subject to demand charges and 14% 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,
2017
, we had
$825.4 million
in available borrowing capacity under the RCF.
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•
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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 crude oil, condensate and NGLs.
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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 consists 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 eleven related-party acquisitions and seven third-party acquisitions, with an aggregate acquisition value of $6.3 billion. 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 or production facilities in the area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing, if necessary. 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.
Stabilization is a process that separates the heavier hydrocarbons (which are also valuable commodities) that are sometimes 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.
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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.
The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of heavier NGLs and contaminants, such as water and carbon dioxide, sulfur compounds, nitrogen or helium. Natural gas is processed to remove unwanted contaminants that would interfere with pipeline transportation or use of the natural gas and to separate those hydrocarbon liquids from the gas that have higher value as NGLs. The removal and separation of individual hydrocarbons through processing is possible due to differences in molecular weight, boiling point, vapor pressure and other physical characteristics.
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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 throughout the pipeline network or 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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Gathering.
Crude oil gathering assets provide the link between crude oil production gathered at the well site or nearby collection points and crude oil terminals, storage facilities, long-haul crude oil pipelines and refineries. Crude oil gathering assets generally consist of a network of small-diameter pipelines that are connected directly to the well site or central receipt points and deliver into large-diameter trunk lines. To the extent there are not enough volumes to justify construction of or connection to a pipeline system, crude oil can also be trucked from a well site to a central collection point.
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Stabilization.
Crude oil stabilization assets process crude oil to meet vapor pressure specifications. Crude oil delivery points, including crude oil terminals, storage facilities, long-haul crude oil pipelines and refineries, often have specific requirements for vapor pressure and temperature, and for the amount of sediment and water that can be contained in any crude oil delivered to them.
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Gathering.
Produced water often accounts for the largest byproduct stream associated with production of crude oil and natural gas. Produced water gathering assets provide the link between well sites or nearby collection points and disposal facilities.
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Disposal.
As a natural byproduct of crude oil and natural gas production, produced water must be recycled or disposed of in order to maintain production. Produced water disposal systems remove hydrocarbon products and other sediments from the produced water in compliance with applicable regulations and re-inject the produced water utilizing permitted disposal wells.
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Fee-based.
Under fee-based arrangements, the service provider typically receives a fee for each unit of (i) natural gas, NGLs, or crude oil gathered, treated, processed and/or transported, or (ii) produced water disposed of, 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 gas and/or NGLs or a percentage of the actual residue gas 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 natural 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 used. 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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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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Processing / Treating Capacity (MBbls/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
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11
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884
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14
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117
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273,381
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2
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3,175
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Utah
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Chipeta
(2)
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Processing
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3
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790
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—
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12
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74,875
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—
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2
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Total
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14
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1,674
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14
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129
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348,256
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2
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3,177
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(1)
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The DJ Basin complex includes the Platte Valley, Fort Lupton, Fort Lupton JT, Hambert JT, which is currently inactive, and Lancaster Trains I and II processing plants; the Platteville amine treating plant; and the Wattenberg gathering system.
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(2)
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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, which is currently inactive.
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Customers.
As of December 31,
2017
, throughput at the DJ Basin complex was from Anadarko and numerous third-party customers. For the year ended December 31,
2017
, Anadarko’s production represented 70% of the DJ Basin complex throughput and the largest third-party customer provided 13% of the throughput.
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Supply.
There were 2,736 active receipt points connected to the DJ Basin complex as of December 31,
2017
. The DJ Basin complex is primarily supplied by the Wattenberg field, in which Anadarko holds interests in over 400,000 net acres in its core position. Anadarko drilled 348 wells and completed 263 wells during the year ended December 31,
2017
.
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Delivery points.
As of December 31,
2017
, the DJ Basin complex had the following delivery points for gas not processed within the DJ Basin complex:
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Anadarko’s Wattenberg plant inlet; and
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Various interconnections with DCP Midstream LP’s (“DCP”) gathering and processing system.
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Customers.
As of December 31,
2017
, throughput at the Chipeta complex was from Anadarko and numerous third-party customers. For the year ended December 31,
2017
, Anadarko’s production represented 74% of the Chipeta complex throughput and the largest third-party customer provided 15% of the throughput.
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Supply.
The Chipeta complex is well positioned to access Anadarko and third-party production in the Uinta Basin where Anadarko holds interests in 238,000 gross acres. Chipeta’s inlet is connected to Anadarko’s Natural Buttes gathering system, the Dominion Energy Questar Pipeline, LLC system (“Questar pipeline”) and Three Rivers Gathering, LLC’s system, which is owned by Andeavor Logistics LP (“Andeavor”).
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Delivery points.
The Chipeta plant delivers NGLs to Enterprise Products Partners LP’s (“Enterprise”) Mid-America Pipeline Company pipeline (“MAPL pipeline”), 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 residue gas delivery points through the following pipelines delivering to markets throughout the Rockies and Western United States:
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CIG pipeline;
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Questar pipeline; and
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◦
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Wyoming Interstate Company’s pipeline (“WIC 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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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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9
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14,620
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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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315
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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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38
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40,443
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1
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1,480
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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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189
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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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520
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41
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43,577
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1
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738
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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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27
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51,179
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1
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1,113
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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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1,453
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129
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165,418
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6
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4,173
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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.
Throughput at the Bison treating facility was from two third-party customers as of December 31,
2017
. The largest customer provided 83% of the throughput for the year ended December 31,
2017
. In connection with Anadarko’s sale of its Powder River Basin coal-bed methane assets in 2015, Anadarko retained its throughput commitment to Bison through 2020.
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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 treating facility is directly connected to Fort Union’s pipeline and the Bison pipeline operated by TransCanada Corporation.
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•
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Customers.
Western Gas Wyoming, L.L.C., 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. To the extent capacity on the system is not used by these customers, it is available to third parties under interruptible agreements.
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•
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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 and their affiliates throughout the Powder River Basin. 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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•
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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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◦
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CIG pipeline;
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◦
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Tallgrass Interstate Gas Transmission system’s pipeline (“TIGT pipeline”); and
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◦
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WIC pipeline.
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•
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Customers.
As of December 31,
2017
, gas gathered and processed through the Hilight system was from numerous third-party customers
. The three largest producers provided 74% of the system throughput for the
year ended December 31,
2017
.
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•
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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 truck and rail loading facilities.
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•
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Customers.
Gas gathered and processed through the Newcastle system was from numerous third-party customers as of December 31,
2017
. The three largest producers provided 79% of the system throughput, with the largest producer providing 44% of the system throughput, for the year ended December 31,
2017
.
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•
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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.
|
•
|
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 intrastate pipeline for transport, distribution and sale.
|
•
|
Customers.
Throughput at the Granger complex was from numerous third-party customers as of December 31,
2017
. For the year ended December 31,
2017
, 78% of the Granger complex throughput was from two third-party customers.
|
•
|
Supply.
The Granger complex is supplied by the Moxa Arch and the Jonah and Pinedale Anticline fields. The Granger gas gathering system had 598 active receipt points as of December 31,
2017
.
|
•
|
Delivery points.
The residue from the Granger complex can be delivered to the following major pipelines:
|
◦
|
CIG pipeline;
|
◦
|
Berkshire Hathaway Energy’s Kern River pipeline (“Kern River pipeline”) via a connect with Andeavor’s Rendezvous pipeline (“Rendezvous pipeline”);
|
◦
|
Questar pipeline;
|
◦
|
Dominion Energy Overthrust Pipeline;
|
◦
|
The Williams Companies, Inc.’s Northwest Pipeline (“NWPL”);
|
◦
|
our OTTCO pipeline; and
|
◦
|
our Mountain Gas Transportation LLC pipeline.
|
•
|
Customers.
As of December 31,
2017
, throughput at the Red Desert complex was from Anadarko and numerous third-party customers. For the year ended December 31,
2017
, 42% of the Red Desert complex throughput was from the two largest third-party customers and 3% was from Anadarko.
|
•
|
Supply.
The Red Desert complex gathers, compresses, treats and processes natural gas and fractionates NGLs produced from the eastern portion of the Greater Green River Basin, providing service primarily to the Red Desert and Washakie Basins.
|
•
|
Delivery points.
Residue from the Red Desert complex is delivered to the CIG and WIC pipelines, while NGLs are delivered to the MAPL pipeline, as well as to truck and rail loading facilities.
|
•
|
Customers
.
As of December 31,
2017
, throughput on the Rendezvous gathering system was primarily from two shippers that have dedicated acreage to the system.
|
•
|
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 Andeavor’s Blacks Fork gas processing plant, which connects to the Questar pipeline, NWPL and the Kern River pipeline via the Rendezvous pipeline.
|
Location
|
|
Asset
|
|
Type
|
|
Processing / Treating Plants
|
|
Processing / Treating Capacity (MMcf/d)
|
|
Processing / Treating / Disposal Capacity (MBbls/d)
|
|
Compressors / Pumps
(1)
|
|
Compression Horsepower
(1)
|
|
Gathering Systems
|
|
Pipeline Miles
|
|||||||
West Texas
|
|
Haley
|
|
Gathering
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
15,300
|
|
|
1
|
|
|
181
|
|
West Texas / New Mexico
|
|
DBM complex
(2)
|
|
Gathering, Processing & Treating
|
|
6
|
|
|
900
|
|
|
18
|
|
|
102
|
|
|
195,835
|
|
|
1
|
|
|
407
|
|
West Texas
|
|
DBJV system
|
|
Gathering & Treating
|
|
9
|
|
|
175
|
|
|
6
|
|
|
71
|
|
|
99,820
|
|
|
1
|
|
|
659
|
|
West Texas
|
|
DBM water systems
|
|
Gathering & Disposal
|
|
—
|
|
|
—
|
|
|
90
|
|
|
12
|
|
|
5,100
|
|
|
2
|
|
|
36
|
|
East Texas
|
|
Mont Belvieu JV
(3)
|
|
Processing
|
|
2
|
|
|
—
|
|
|
170
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
South Texas
|
|
Brasada complex
|
|
Gathering, Processing & Treating
|
|
3
|
|
|
200
|
|
|
15
|
|
|
14
|
|
|
30,450
|
|
|
1
|
|
|
57
|
|
South Texas
|
|
Springfield system
(4)
|
|
Gathering and Treating
|
|
3
|
|
|
—
|
|
|
75
|
|
|
105
|
|
|
169,644
|
|
|
2
|
|
|
815
|
|
Total
|
|
|
|
|
|
23
|
|
|
1,275
|
|
|
374
|
|
|
314
|
|
|
516,149
|
|
|
8
|
|
|
2,155
|
|
(1)
|
Includes owned, rented and leased compressors and compression horsepower.
|
(2)
|
Excludes
1,400
gpm of amine treating capacity at the DBM complex.
|
(3)
|
We own a 25% interest in the Mont Belvieu JV, which owns two NGL fractionation trains. A third party serves as the operator.
|
(4)
|
We own a 50.1% interest in the Springfield system and serve as the operator.
|
•
|
Customers.
As of December 31,
2017
, throughput at the Haley system was from Anadarko and two third-party producers. Anadarko’s production represented 88% of the system throughput for the year ended December 31,
2017
.
|
•
|
Supply.
Anadarko holds interests in approximately 590,000 gross (240,000 net) 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, L.P.’s pipeline for ultimate delivery into Energy Transfer Partners, LP’s (“ETP”) Oasis pipeline (the “Oasis pipeline”). The rich service delivery point is into a high pressure gathering line, which is part of our DBJV system.
|
•
|
Customers.
As of December 31,
2017
, gas gathered and processed through the DBM complex was from Anadarko and numerous third-party customers. For the year ended December 31,
2017
, 67% of the throughput was from the six largest third-party customers and 8% was from Anadarko.
|
•
|
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 interests in approximately 590,000 gross (240,000 net) acres within the Delaware Basin.
|
•
|
Delivery points.
Residue gas produced at the facility is delivered to the Ramsey Residue Lines, which extend from the DBM complex to the south and to the north, with both lines connecting with Kinder Morgan, Inc.’s interstate pipeline system (see
Transportation
within these Items 1 and 2). NGL production is delivered into both the Sand Hills pipeline and Lone Star NGL LLC’s pipeline.
|
•
|
Customers.
Throughput at the DBJV system was from Anadarko and one third-party producer as of December 31,
2017
. Anadarko’s production represented 78% of the system throughput for the year ended December 31,
2017
.
|
•
|
Supply.
The system gathers lean Penn gas, as well as liquids-rich Bone Spring, Avalon and Wolfcamp gas.
|
•
|
Delivery points.
Avalon, Bone Spring and Wolfcamp gas is dehydrated, compressed and delivered to the Bone Spring Gas Processing plant (the “Bone Spring plant”), the Mi Vida Gas Processing plant (the “Mi Vida plant”) and the DBM complex for processing, while lean Penn gas is delivered into Enterprise GC, L.P.’s pipeline. Residue gas from the Bone Spring and Mi Vida plants is delivered into the Oasis pipeline or Transwestern Pipeline Company LLC’s pipeline.
|
•
|
Customers.
As of December 31,
2017
, throughput at the DBM water systems was from Anadarko and one third-party producer. Anadarko’s production represented 93% of the throughput for the year ended December 31,
2017
.
|
•
|
Supply.
The systems gather and dispose produced water for Anadarko and a third-party producer.
|
•
|
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, TEP and Enterprise’s Panola Pipeline, in which Anadarko has a 15% equity interest. Individual NGLs are delivered to end users either through customer-owned pipelines that are connected to nearby petrochemical plants or via export terminal.
|
•
|
Customers.
Throughput at the Brasada complex was from one third-party customer as of December 31,
2017
. In the first quarter of 2017, Anadarko completed the sale of its Eagleford shale upstream assets to a third party.
|
•
|
Supply.
Supply of gas and NGLs comes from throughput gathered by the Springfield system.
|
•
|
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.
Throughput at the Springfield system was from numerous third-party customers as of December 31,
2017
. In the first quarter of 2017, Anadarko completed the sale of its Eagleford shale upstream assets to a third party.
|
•
|
Supply.
Supply of gas and oil comes from third-party production in the Eagleford shale.
|
•
|
Delivery points.
The gas gathering system delivers rich gas to our Brasada complex, the Raptor processing plant owned by Targa Resources Corp. and Sanchez Midstream Partners LP, and to processing plants operated by Enterprise, ETP and Kinder Morgan, Inc. The oil gathering system has delivery points to Plains All American Pipeline, Kinder Morgan, Inc.’s Double Eagle Pipeline, Hilcorp Energy Company’s Harvest Pipeline and NuStar Energy L.P.’s Pipeline.
|
Location
|
|
Asset
|
|
Type
|
|
Compressors
|
|
Compression Horsepower
|
|
Gathering Systems
|
|
Pipeline Miles
|
||||
North-central Pennsylvania
|
|
Marcellus
(1)
|
|
Gathering
|
|
5
|
|
|
6,900
|
|
|
3
|
|
|
144
|
|
(1)
|
We own a 33.75% interest in the Marcellus Interest gathering systems.
|
•
|
Customers.
As of December 31,
2017
, the Marcellus Interest gathering systems had multiple priority shippers. The largest producer provided 75% of the throughput for the year ended December 31,
2017
. Capacity not used by priority shippers is available to third parties as determined by the operating partner, Alta Resources Development, LLC. In the first quarter of 2017, Anadarko completed the sale of its operated and non-operated upstream assets and operated midstream assets (excluding our interests) in the Marcellus shale to a third party.
|
•
|
Supply and delivery points.
The Marcellus Interest gathering systems are well positioned to serve dry gas production from the Marcellus shale. The Marcellus Interest gathering systems have access to Transcontinental Gas Pipe Line Company, LLC’s pipeline.
|
Location
|
|
Asset
|
|
Type
|
|
Compressors /
Pump Stations
|
|
Operational Horsepower
|
|
Pipeline Miles
|
|||
Colorado, Kansas, Oklahoma
|
|
White Cliffs
(1) (2)
|
|
Oil
|
|
24
|
|
|
33,800
|
|
|
1,054
|
|
Utah
|
|
GNB NGL
(1)
|
|
NGL
|
|
—
|
|
|
—
|
|
|
33
|
|
Northeast Wyoming
|
|
MIGC
(1)
|
|
Gas
|
|
2
|
|
|
3,360
|
|
|
239
|
|
Southwest Wyoming
|
|
OTTCO
|
|
Gas
|
|
1
|
|
|
3,174
|
|
|
217
|
|
Colorado, Oklahoma, Texas
|
|
FRP
(1) (3)
|
|
NGL
|
|
6
|
|
|
12,000
|
|
|
447
|
|
Texas, Oklahoma
|
|
TEG
(3)
|
|
NGL
|
|
8
|
|
|
748
|
|
|
137
|
|
Texas
|
|
TEP
(1) (3)
|
|
NGL
|
|
12
|
|
|
27,000
|
|
|
593
|
|
Texas
|
|
Ramsey Residue Lines
(1)
|
|
Gas
|
|
—
|
|
|
—
|
|
|
18
|
|
Total
|
|
|
|
|
|
53
|
|
|
80,082
|
|
|
2,738
|
|
(1)
|
White Cliffs, GNB NGL, MIGC, FRP, TEP and the Ramsey Residue Lines (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.
The White Cliffs pipeline had multiple committed shippers, including Anadarko, as of December 31,
2017
. In addition, other parties may ship on the White Cliffs pipeline at FERC-based rates. An expansion project was completed in 2017 that increased the pipeline’s capacity from 150 MBbls/d to approximately 180 MBbls/d. The White Cliffs dual pipeline system provides crude oil takeaway capacity from Platteville, Colorado to Cushing, Oklahoma.
|
•
|
Supply.
The White Cliffs pipeline is supplied by production from the DJ Basin.
|
•
|
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.
|
•
|
Customers.
Anadarko was the only shipper on the GNB NGL pipeline as of December 31,
2017
.
|
•
|
Supply.
The GNB NGL pipeline receives NGLs from Chipeta’s gas processing facility and Andeavor’s Stagecoach/Iron Horse gas processing complex.
|
•
|
Delivery points.
The GNB NGL pipeline delivers NGLs to the MAPL pipeline, 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.
Anadarko was the largest firm shipper on the MIGC system, with 88% of the throughput for the year ended December 31,
2017
. The remaining throughput on the MIGC system was from numerous 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 pipeline;
|
◦
|
TIGT pipeline; and
|
◦
|
WIC pipeline.
|
•
|
Customers.
For the year ended December 31,
2017
, 10% 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 contracts that contain minimum volume commitments 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.
|
•
|
Front Range Pipeline.
FRP provides takeaway capacity from the DJ Basin in Northeast Colorado. FRP has receipt points at gas plants in Weld County, Colorado (including the 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. As of December 31,
2017
, FRP had multiple committed shippers, including Anadarko. FRP provides capacity to 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 as of December 31,
2017
.
|
•
|
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 the MAPL pipeline. As of December 31,
2017
, TEP had multiple committed shippers, including Anadarko. TEP provides capacity to other shippers at the posted FERC tariff rates.
|
•
|
Mentone processing plant:
We are currently constructing two cryogenic processing trains at a new processing plant located in Loving County, Texas. Mentone Trains I and II will each have a capacity of 200 MMcf/d and we expect these trains to be completed during the third and fourth quarters of 2018, respectively. The Mentone processing plant will be part of the DBM complex, and upon completion of Mentone Trains I and II, the DBM complex will have a total processing capacity of 1,300 MMcf/d.
|
•
|
Latham processing plant:
We have sanctioned two cryogenic processing trains at a new processing plant located in Weld County, Colorado. Construction of Latham Trains I and II (each with a capacity of 200 MMcf/d) is expected to begin by the third quarter of 2018 and we expect these trains to be completed during the first and third quarters of 2019, respectively. The Latham processing plant will be part of the DJ Basin complex, and upon completion of Latham Trains I and II, the DJ Basin complex will have a total processing capacity of 1,250 MMcf/d.
|
Asset
|
|
Competitor(s)
|
Bison facility
|
|
Thunder Creek Gas Services, LLC and Fort Union (treating only)
|
Brasada complex
|
|
Enterprise, ETP, Targa Resources Partners LP, Kinder Morgan, Inc., Plains All American Pipeline and Howard Energy Partners
|
Chipeta complex
|
|
Andeavor and Kinder Morgan, Inc.
|
DBJV system
|
|
ETP, Targa Resources Partners LP, Enterprise GC, L.P., EagleClaw Midstream Ventures, LLC, Enlink Midstream Partners, LP and Vaquero Midstream LLC
|
DBM complex
|
|
ETP, Targa Resources Partners LP, Enterprise GC, L.P., EagleClaw Midstream Ventures, LLC, Enlink Midstream Partners, LP, Vaquero Midstream LLC, MPLX LP, Crestwood Midstream Partners LP and Noble Midstream Partners LP
|
DBM water systems
|
|
NGL Water Solutions, LLC, Mesquite SWD, Inc. and Oilfield Water Logistics, LLC
|
DJ Basin complex
|
|
DCP, AKA Energy Group, LLC and Discovery Midstream Partners
|
Fort Union system
|
|
Bison treating facility (carbon dioxide treating services only), MIGC, Thunder Creek Gas Services, LLC and TransCanada Corporation
|
Granger complex
|
|
Williams Field Services Company, LLC, Enterprise/Jonah Gas Gathering Company and Andeavor
|
Haley system
|
|
ETP, Targa Resources Partners LP and Enterprise GC, L.P.
|
Hilight system
|
|
ONEOK Gas Gathering Company, Thunder Creek Gas Services, LLC, Crestwood-Access, Tallgrass Energy Partners, LP and Evolution Midstream
|
Marcellus Interest gathering systems
|
|
ETP and National Fuel Gas Midstream Corporation
|
Mont Belvieu JV
|
|
Targa Resources Partners LP, Phillips 66, Lone Star NGL LLC and ONEOK Partners, LP
|
Newcastle system
|
|
Tallgrass Energy Partners, LP
|
Red Desert complex
|
|
Williams Field Services Company, LLC and Andeavor
|
Rendezvous system
|
|
No significant direct competition
|
Springfield system
|
|
Enterprise, ETP, Targa Resources Partners LP, Kinder Morgan, Inc., Plains All American Pipeline, Southcross Energy Partners, L.P., Williams Field Services Company, LLC and Howard Energy Partners
|
•
|
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 Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, monitoring, and reporting requirements, and which the U.S. Environmental Protection Agency (the “EPA”) has relied upon as authority for adopting climate change regulatory initiatives relating to greenhouse gas (“GHG”) emissions;
|
•
|
the 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 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 Resource Conservation and Recovery Act, which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;
|
•
|
the Safe Drinking Water Act, which regulates the quality of the nation’s public drinking water through adoption of drinking water standards and control over the injection of waste fluids into below-ground formations that may adversely affect drinking water sources;
|
•
|
the 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; and
|
•
|
U.S. Department of Transportation regulations, which relate to advancing the safe transportation of energy and hazardous materials and emergency preparedness.
|
•
|
our ability to pay distributions to our unitholders;
|
•
|
our and Anadarko’s assumptions about the energy market;
|
•
|
future throughput (including Anadarko production) which is gathered or processed by or transported through our assets;
|
•
|
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 price of, oil, natural gas, NGLs and related products or services;
|
•
|
our ability to mitigate exposure to the commodity price risks inherent in our percent-of-proceeds and keep-whole contracts through the extension of our commodity price swap agreements with Anadarko, or otherwise;
|
•
|
weather and natural disasters;
|
•
|
inflation;
|
•
|
the availability of goods and services;
|
•
|
general economic conditions, internationally, 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 the RCF;
|
•
|
our ability to repay debt;
|
•
|
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 from Anadarko or third parties, and Anadarko’s ability to generate an inventory of assets suitable for acquisition;
|
•
|
non-payment or non-performance of Anadarko or other significant customers, including under our gathering, processing, transportation and disposal agreements and our $260.0 million note receivable from Anadarko;
|
•
|
the timing, amount and terms of future issuances of equity and debt securities;
|
•
|
the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the National Transportation Safety Board (“NTSB”) related to Anadarko’s operations in Colorado, and continued or additional disruptions in operations that may occur as Anadarko and we comply with regulatory orders or other state or local changes in laws or regulations in Colorado; and
|
•
|
other factors discussed below and elsewhere in this Item 1A, under the caption
Critical Accounting 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 and its ability to finance its operations;
|
•
|
the availability of capital on favorable terms 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, flowline, pipeline, and operating risks, including potential environmental liabilities;
|
•
|
transportation capacity constraints and interruptions;
|
•
|
adverse effects of governmental and environmental regulation;
|
•
|
shareholder activism with respect to Anadarko’s stock or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas by Anadarko; 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 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 oil and natural gas;
|
•
|
the volume of oil and natural gas we gather, compress, process, treat and/or 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 companies;
|
•
|
regulatory action affecting the supply of or demand for oil or 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; and
|
•
|
the amount of cash reserves established by our general partner.
|
•
|
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.
|
•
|
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 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.
|
•
|
Ground-Level Ozone Standards.
In October 2015, the EPA issued a rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion. The EPA published a final rule in November 2017 that issued attainment or unclassifiable area designations with respect to ground-level ozone for numerous counties in the United States and is expected to issue non-attainment area designations in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states with counties that are designated as non-attainment are expected to implement more stringent regulations for those non-attainment areas, which could require installation of new emission controls on some of our equipment, resulting in longer permitting timelines, and significantly increase our capital expenditures and operating costs.
|
•
|
Reduction of Methane Emissions by the Oil and Gas Industry.
In June 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed oil and natural gas production and natural gas processing and transmission facilities. The EPA’s rule is comprised of New Source Performance Standards, known as Subpart OOOOa, which require certain new, modified, or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued New Source Performance Standards to, among other things, hydraulically fractured oil and natural gas well completions, fugitive emissions from well sites and compressors, and equipment leaks at natural gas processing plants and pneumatic pumps. However, in June 2017, the EPA published a proposed rule to stay certain portions of these Subpart OOOOa standards for two years and revisit the entirety of the 2016 standard, but it has not yet published a final rule and, as a result, the June 2016 standards remain in effect but future implementation of the 2016 standards is uncertain at this time. Furthermore, the Bureau of Land Management (“BLM”) published a final rule in November 2016 that requires a reduction in methane emissions from venting, flaring and leaking on public lands. However, in December 2017, the BLM published a final rule that temporarily suspends or delays certain requirements contained in the 2016 final rule until January 17, 2019. The suspension of the November 2016 final rule is being challenged by several non-governmental organizations and states. Notwithstanding the current uncertainty of the 2016 rule, we have taken measures to enter into a voluntary regime, together with certain other oil and natural gas exploration and production operators, to reduce methane emissions. At the state level, some states where we operate, including Colorado, have issued requirements for the performance of leak detection programs that identify and repair methane leaks at certain oil and natural gas sources. Compliance with these rules or with any future federal or state methane regulations could, among other things, require installation of new emission controls on some of our equipment and significantly increase our capital expenditures and operating costs.
|
•
|
Reduction of GHG Emissions.
The U.S. Congress and the EPA, in addition to some state and regional authorities, have in recent years considered legislation or regulations to reduce emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislation, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the Clean Air Act and may require the installation of “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs together with other criteria pollutants. Also, certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of GHG emissions from specified onshore and offshore production sources. In December 2015, the United States joined the international community at the 21
st
Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France and agreed to review its GHG emissions and set GHG emission reduction goals every five years beginning in 2020. Although this agreement does not create any binding obligations, it does include pledges to voluntarily limit or reduce future emissions. In August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Climate Agreement, which would result in an effective exit date of November 2020. Notwithstanding any withdrawal from this agreement, the implementation of substantial limitations on GHG emissions in areas where we conduct operations could adversely affect demand for oil and natural gas.
|
•
|
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 or losses of hydrocarbons or produced water as a result of the malfunction of equipment or facilities;
|
•
|
fires and explosions (for example, see
Items Affecting the Comparability of Our Financial Results
, under Part II, Item 7 of this Form 10-K for a discussion of the incident at the DBM complex); and
|
•
|
other hazards that could also result in personal injury, loss of life, pollution, natural resource damages and/or curtailment 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 devote significant time to the business of Anadarko and are compensated by Anadarko accordingly. For example, all of the equity incentive compensation currently provided to the officers of our general partner is tied to Anadarko’s common stock rather than our or WGP’s common units.
|
•
|
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 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 has limited, and intends to continue 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 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, 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 other 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
|
||||||||
2017
|
|
|
|
|
|
|
|
|
||||||||
High Price
|
|
$
|
52.89
|
|
|
$
|
57.15
|
|
|
$
|
61.78
|
|
|
$
|
67.44
|
|
Low Price
|
|
42.68
|
|
|
48.04
|
|
|
51.65
|
|
|
57.81
|
|
||||
Distribution per common unit
|
|
0.920
|
|
|
0.905
|
|
|
0.890
|
|
|
0.875
|
|
||||
2016
|
|
|
|
|
|
|
|
|
||||||||
High Price
|
|
$
|
60.44
|
|
|
$
|
55.24
|
|
|
$
|
53.45
|
|
|
$
|
48.50
|
|
Low Price
|
|
52.52
|
|
|
46.85
|
|
|
39.73
|
|
|
25.40
|
|
||||
Distribution per common unit
|
|
0.860
|
|
|
0.845
|
|
|
0.830
|
|
|
0.815
|
|
|
|
Acquisition Date
|
|
Percentage Acquired
|
|
Affiliate or Third-party Acquisition
|
|
Non-Operated Marcellus Interest
(1)
|
|
03/01/2013
|
|
33.75
|
%
|
|
Anadarko
|
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
(2)
|
|
03/03/2014
|
|
Various
(2)
|
|
|
Anadarko
|
DBM
|
|
11/25/2014
|
|
100
|
%
|
|
Third party
|
DBJV system
|
|
03/02/2015
|
|
50
|
%
|
|
Anadarko
|
Springfield system
|
|
03/14/2016
|
|
50.1
|
%
|
|
Anadarko
|
DBJV system
(1)
|
|
03/17/2017
|
|
50
|
%
|
|
Third party
|
(1)
|
See
Property exchange
below.
|
(2)
|
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
|
||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|||||||||||
Statement of Operations Data (for the year ended):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues and other
|
|
$
|
2,248,356
|
|
|
$
|
1,804,270
|
|
|
$
|
1,752,072
|
|
|
$
|
1,533,377
|
|
|
$
|
1,200,060
|
|
Operating income (loss)
|
|
707,271
|
|
|
708,208
|
|
|
157,330
|
|
|
554,731
|
|
|
325,619
|
|
|||||
Net income (loss)
|
|
578,218
|
|
|
602,294
|
|
|
14,207
|
|
|
456,668
|
|
|
288,244
|
|
|||||
Net income attributable to noncontrolling interest
|
|
10,735
|
|
|
10,963
|
|
|
10,101
|
|
|
14,025
|
|
|
10,816
|
|
|||||
Net income (loss) attributable to Western Gas Partners, LP
|
|
567,483
|
|
|
591,331
|
|
|
4,106
|
|
|
442,643
|
|
|
277,428
|
|
|||||
Net income (loss) per common unit – basic
|
|
1.30
|
|
|
1.74
|
|
|
(1.95
|
)
|
|
2.13
|
|
|
1.83
|
|
|||||
Net income (loss) per common unit – diluted
|
|
1.30
|
|
|
1.74
|
|
|
(1.95
|
)
|
|
2.12
|
|
|
1.83
|
|
|||||
Distributions per unit
|
|
3.590
|
|
|
3.350
|
|
|
3.050
|
|
|
2.650
|
|
|
2.280
|
|
|||||
Balance Sheet Data (at year end):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
|
$
|
8,014,350
|
|
|
$
|
7,733,028
|
|
|
$
|
7,301,197
|
|
|
$
|
7,549,785
|
|
|
$
|
5,328,224
|
|
Total long-term liabilities
|
|
3,619,006
|
|
|
3,281,944
|
|
|
3,147,681
|
|
|
2,699,244
|
|
|
1,659,229
|
|
|||||
Total equity and partners’ capital
|
|
3,971,011
|
|
|
4,135,779
|
|
|
3,918,028
|
|
|
4,568,462
|
|
|
3,422,675
|
|
|||||
Cash Flow Data (for the year ended):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash flows provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
|
$
|
901,495
|
|
|
$
|
917,585
|
|
|
$
|
785,645
|
|
|
$
|
694,495
|
|
|
$
|
601,335
|
|
Investing activities
|
|
(763,604
|
)
|
|
(1,105,534
|
)
|
|
(500,277
|
)
|
|
(2,740,175
|
)
|
|
(1,858,912
|
)
|
|||||
Financing activities
|
|
(417,002
|
)
|
|
447,841
|
|
|
(254,389
|
)
|
|
2,011,970
|
|
|
938,324
|
|
|||||
Capital expenditures
|
|
(673,638
|
)
|
|
(473,858
|
)
|
|
(637,503
|
)
|
|
(804,822
|
)
|
|
(851,771
|
)
|
|||||
Throughput (MMcf/d except throughput measured in barrels):
|
||||||||||||||||||||
Total throughput for natural gas assets
|
|
3,680
|
|
|
4,064
|
|
|
4,300
|
|
|
3,984
|
|
|
3,611
|
|
|||||
Throughput attributable to noncontrolling interest for natural gas assets
|
|
105
|
|
|
124
|
|
|
142
|
|
|
165
|
|
|
168
|
|
|||||
Total throughput attributable to Western Gas Partners, LP for natural gas assets
|
|
3,575
|
|
|
3,940
|
|
|
4,158
|
|
|
3,819
|
|
|
3,443
|
|
|||||
Throughput for crude oil, NGL and produced water assets (MBbls/d)
|
|
201
|
|
|
184
|
|
|
186
|
|
|
154
|
|
|
62
|
|
|||||
Key Performance Metrics (for the year ended):
(1)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Adjusted gross margin for natural gas assets
|
|
$
|
1,222,632
|
|
|
$
|
1,194,877
|
|
|
$
|
1,119,555
|
|
|
$
|
993,397
|
|
|
$
|
775,040
|
|
Adjusted gross margin for crude oil, NGL and produced water assets
|
|
153,846
|
|
|
142,566
|
|
|
131,492
|
|
|
103,102
|
|
|
31,664
|
|
|||||
Adjusted gross margin per Mcf for natural gas assets
|
|
0.94
|
|
|
0.83
|
|
|
0.74
|
|
|
0.71
|
|
|
0.62
|
|
|||||
Adjusted gross margin per Bbl for crude oil, NGL and produced water assets
|
|
2.10
|
|
|
2.11
|
|
|
1.93
|
|
|
1.84
|
|
|
1.40
|
|
|||||
Adjusted EBITDA
|
|
1,060,988
|
|
|
1,028,208
|
|
|
907,568
|
|
|
782,900
|
|
|
539,401
|
|
|||||
Distributable cash flow
|
|
928,967
|
|
|
852,446
|
|
|
781,383
|
|
|
661,133
|
|
|
455,238
|
|
(1)
|
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
How We Evaluate Our Operations
under Part II, Item 7 of this Form 10-K.
|
|
|
Owned and
Operated
|
|
Operated
Interests
|
|
Non-Operated
Interests
|
|
Equity
Interests
|
||||
Gathering systems
(1)
|
|
12
|
|
|
3
|
|
|
3
|
|
|
2
|
|
Treating facilities
|
|
19
|
|
|
3
|
|
|
—
|
|
|
3
|
|
Natural gas processing plants/trains
|
|
20
|
|
|
4
|
|
|
—
|
|
|
2
|
|
NGL pipelines
|
|
2
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Natural gas pipelines
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Oil pipelines
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
(1)
|
Includes the DBM water systems.
|
•
|
In March 2017, we acquired the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0 million of cash consideration, resulting in a net gain of
$125.7 million
. See
Acquisitions and Divestitures
under Part I, Items 1 and 2 of this Form 10-K for additional information.
|
•
|
In May 2017, we reached an agreement with Anadarko to settle the outstanding Deferred purchase price obligation - Anadarko, arising from our acquisition of DBJV, whereby we made a cash payment to Anadarko of $37.3 million during the second quarter of 2017.
|
•
|
On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis. See
Equity Offerings
under Part I, Items 1 and 2 of this Form 10-K for additional information.
|
•
|
We commenced operation of the DBM water systems in the second quarter of 2017 and Train VI at the DBM complex (with capacity of 200 MMcf/d) in the fourth quarter of 2017.
|
•
|
In June 2017, we closed on the sale of our Helper and Clawson systems, which resulted in a net gain on divestiture of
$16.3 million
. See
Acquisitions and Divestitures
under Part I, Items 1 and 2 of this Form 10-K for additional information.
|
•
|
In February 2017, Anadarko elected to extend the conversion date of the Class C units from December 31, 2017, to March 1, 2020.
|
•
|
We received
$52.9 million
in cash proceeds from insurers in final settlement of our claims related to the incident at the DBM complex, including
$29.9 million
for business interruption insurance claims and
$23.0 million
for property insurance claims. See
Items Affecting the Comparability of Our Financial Results
within this
Item 7
for additional information.
|
•
|
We raised our distribution to
$0.920
per unit for the
fourth
quarter of
2017
, representing a
2%
increase
over the distribution for the
third
quarter of
2017
and a
7%
increase
over the distribution for the
fourth
quarter of
2016
.
|
•
|
Throughput attributable to Western Gas Partners, LP for natural gas assets totaled
3,575
MMcf/d for the
year ended December 31, 2017
, representing a
9%
decrease
compared to the
year ended December 31, 2016
.
|
•
|
Throughput for crude oil, NGL and produced water assets totaled
201
MBbls/d for the
year ended December 31, 2017
, representing a
9%
increase
compared to the
year ended December 31, 2016
.
|
•
|
Operating income (loss) was
$707.3 million
for the
year ended December 31, 2017
, which was approximately the same as for the
year ended December 31, 2016
.
|
•
|
Adjusted gross margin for natural gas assets (as defined under the caption
How We Evaluate Our Operations
within this
Item 7
) averaged
$0.94
per Mcf for the
year ended December 31, 2017
, representing a
13%
increase
compared to the
year ended December 31, 2016
.
|
•
|
Adjusted gross margin for crude oil, NGL and produced water assets (as defined under the caption
How We Evaluate Our Operations
within this
Item 7
) averaged
$2.10
per Bbl for the
year ended December 31, 2017
, which was approximately the same as for the
year ended December 31, 2016
.
|
•
|
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 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
|
|
2017
|
|
2016
|
|
2015
|
||||||
Reconciliation of Operating income (loss) to Adjusted gross margin
|
|
|
|
|
|
|
||||||
Operating income (loss)
|
|
$
|
707,271
|
|
|
$
|
708,208
|
|
|
$
|
157,330
|
|
Add:
|
|
|
|
|
|
|
||||||
Distributions from equity investments
|
|
110,465
|
|
|
103,423
|
|
|
98,298
|
|
|||
Operation and maintenance
|
|
315,994
|
|
|
308,010
|
|
|
331,972
|
|
|||
General and administrative
|
|
47,796
|
|
|
45,591
|
|
|
41,319
|
|
|||
Property and other taxes
|
|
46,818
|
|
|
40,145
|
|
|
33,288
|
|
|||
Depreciation and amortization
|
|
290,874
|
|
|
272,933
|
|
|
272,611
|
|
|||
Impairments
|
|
178,374
|
|
|
15,535
|
|
|
515,458
|
|
|||
Less:
|
|
|
|
|
|
|
||||||
Gain (loss) on divestiture and other, net
|
|
132,388
|
|
|
(14,641
|
)
|
|
57,024
|
|
|||
Proceeds from business interruption insurance claims
|
|
29,882
|
|
|
16,270
|
|
|
—
|
|
|||
Equity income, net – affiliates
|
|
85,194
|
|
|
78,717
|
|
|
71,251
|
|
|||
Reimbursed electricity-related charges recorded as revenues
|
|
56,823
|
|
|
59,733
|
|
|
54,175
|
|
|||
Adjusted gross margin attributable to noncontrolling interest
|
|
16,827
|
|
|
16,323
|
|
|
16,779
|
|
|||
Adjusted gross margin
|
|
$
|
1,376,478
|
|
|
$
|
1,337,443
|
|
|
$
|
1,251,047
|
|
Adjusted gross margin for natural gas assets
|
|
$
|
1,222,632
|
|
|
$
|
1,194,877
|
|
|
$
|
1,119,555
|
|
Adjusted gross margin for crude oil, NGL and produced water assets
|
|
153,846
|
|
|
142,566
|
|
|
131,492
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2017
|
|
2016
|
|
2015
|
||||||
Reconciliation of Net income (loss) attributable to Western Gas Partners, LP to Adjusted EBITDA
|
|
|
|
|
|
|
||||||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
567,483
|
|
|
$
|
591,331
|
|
|
$
|
4,106
|
|
Add:
|
|
|
|
|
|
|
||||||
Distributions from equity investments
|
|
110,465
|
|
|
103,423
|
|
|
98,298
|
|
|||
Non-cash equity-based compensation expense
|
|
4,947
|
|
|
5,591
|
|
|
4,402
|
|
|||
Interest expense
|
|
142,386
|
|
|
114,921
|
|
|
113,872
|
|
|||
Income tax expense
|
|
4,905
|
|
|
8,372
|
|
|
45,532
|
|
|||
Depreciation and amortization
(1)
|
|
288,087
|
|
|
270,311
|
|
|
270,004
|
|
|||
Impairments
|
|
178,374
|
|
|
15,535
|
|
|
515,458
|
|
|||
Other expense
(1)
|
|
145
|
|
|
224
|
|
|
1,290
|
|
|||
Less:
|
|
|
|
|
|
|
||||||
Gain (loss) on divestiture and other, net
|
|
132,388
|
|
|
(14,641
|
)
|
|
57,024
|
|
|||
Equity income, net – affiliates
|
|
85,194
|
|
|
78,717
|
|
|
71,251
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Other income
(1)
|
|
1,283
|
|
|
524
|
|
|
219
|
|
|||
Income tax benefit
|
|
39
|
|
|
—
|
|
|
—
|
|
|||
Adjusted EBITDA
|
|
$
|
1,060,988
|
|
|
$
|
1,028,208
|
|
|
$
|
907,568
|
|
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
|
$
|
901,495
|
|
|
$
|
917,585
|
|
|
$
|
785,645
|
|
Interest (income) expense, net
|
|
125,486
|
|
|
98,021
|
|
|
96,972
|
|
|||
Uncontributed cash-based compensation awards
|
|
25
|
|
|
856
|
|
|
214
|
|
|||
Accretion and amortization of long-term obligations, net
|
|
(4,254
|
)
|
|
3,789
|
|
|
(17,698
|
)
|
|||
Current income tax (benefit) expense
|
|
2,408
|
|
|
5,817
|
|
|
34,186
|
|
|||
Other (income) expense, net
|
|
(1,299
|
)
|
|
(479
|
)
|
|
619
|
|
|||
Distributions from equity investments in excess of cumulative earnings – affiliates
|
|
23,085
|
|
|
21,238
|
|
|
16,244
|
|
|||
Changes in operating working capital:
|
|
|
|
|
|
|
||||||
Accounts receivable, net
|
|
16,127
|
|
|
48,947
|
|
|
4,371
|
|
|||
Accounts and imbalance payables and accrued liabilities, net
|
|
6,930
|
|
|
(58,359
|
)
|
|
(1,006
|
)
|
|||
Other, net
|
|
4,491
|
|
|
4,367
|
|
|
720
|
|
|||
Adjusted EBITDA attributable to noncontrolling interest
|
|
(13,506
|
)
|
|
(13,574
|
)
|
|
(12,699
|
)
|
|||
Adjusted EBITDA
|
|
$
|
1,060,988
|
|
|
$
|
1,028,208
|
|
|
$
|
907,568
|
|
Cash flow information of Western Gas Partners, LP
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
|
$
|
901,495
|
|
|
$
|
917,585
|
|
|
$
|
785,645
|
|
Net cash used in investing activities
|
|
(763,604
|
)
|
|
(1,105,534
|
)
|
|
(500,277
|
)
|
|||
Net cash provided by (used in) financing activities
|
|
(417,002
|
)
|
|
447,841
|
|
|
(254,389
|
)
|
(1)
|
Includes our 75% share of depreciation and amortization; other expense; and other income attributable to the Chipeta complex. Other expense also includes
$0.1 million
,
$0.2 million
and
$0.4 million
of lower of cost or market inventory adjustments, primarily at the DBM complex for the years ended
December 31, 2017
, 2016 and 2015, respectively.
|
|
|
Year Ended December 31,
|
||||||||||
thousands except Coverage ratio
|
|
2017
|
|
2016
|
|
2015
|
||||||
Reconciliation of Net income (loss) attributable to Western Gas Partners, LP to Distributable cash flow and calculation of the Coverage ratio
|
|
|
|
|
|
|
||||||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
567,483
|
|
|
$
|
591,331
|
|
|
$
|
4,106
|
|
Add:
|
|
|
|
|
|
|
||||||
Distributions from equity investments
|
|
110,465
|
|
|
103,423
|
|
|
98,298
|
|
|||
Non-cash equity-based compensation expense
|
|
4,947
|
|
|
5,591
|
|
|
4,402
|
|
|||
Non-cash settled interest expense, net
(1)
|
|
71
|
|
|
(7,747
|
)
|
|
14,400
|
|
|||
Income tax (benefit) expense
|
|
4,866
|
|
|
8,372
|
|
|
45,532
|
|
|||
Depreciation and amortization
(2)
|
|
288,087
|
|
|
270,311
|
|
|
270,004
|
|
|||
Impairments
|
|
178,374
|
|
|
15,535
|
|
|
515,458
|
|
|||
Above-market component of swap agreements with Anadarko
(3)
|
|
58,551
|
|
|
45,820
|
|
|
18,449
|
|
|||
Other expense
(2)
|
|
145
|
|
|
224
|
|
|
1,290
|
|
|||
Less:
|
|
|
|
|
|
|
||||||
Gain (loss) on divestiture and other, net
|
|
132,388
|
|
|
(14,641
|
)
|
|
57,024
|
|
|||
Equity income, net – affiliates
|
|
85,194
|
|
|
78,717
|
|
|
71,251
|
|
|||
Cash paid for maintenance capital expenditures
(2)
|
|
49,684
|
|
|
63,630
|
|
|
53,882
|
|
|||
Capitalized interest
|
|
6,826
|
|
|
5,562
|
|
|
8,318
|
|
|||
Cash paid for (reimbursement of) income taxes
|
|
1,194
|
|
|
838
|
|
|
(138
|
)
|
|||
Series A Preferred unit distributions
|
|
7,453
|
|
|
45,784
|
|
|
—
|
|
|||
Other income
(2)
|
|
1,283
|
|
|
524
|
|
|
219
|
|
|||
Distributable cash flow
|
|
$
|
928,967
|
|
|
$
|
852,446
|
|
|
$
|
781,383
|
|
Distributions declared
(4)
|
|
|
|
|
|
|
||||||
Limited partners – common units
|
|
$
|
538,244
|
|
|
|
|
|
||||
General partner
|
|
286,624
|
|
|
|
|
|
|||||
Total
|
|
$
|
824,868
|
|
|
|
|
|
||||
Coverage ratio
|
|
1.13
|
|
x
|
|
|
|
(1)
|
Includes amounts 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. Other expense also includes
$0.1 million
,
$0.2 million
and
$0.4 million
of lower of cost or market inventory adjustments, primarily at the DBM complex for the years ended
December 31, 2017
, 2016 and 2015, respectively.
|
(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)
|
Reflects cash distributions of
$3.590
per unit declared for the
year ended December 31, 2017
, including the cash distribution of $0.920 per unit paid on February 13, 2018, for the fourth-quarter 2017 distribution.
|
•
|
DBJV acquisition.
In March 2015, we acquired Anadarko’s interest in DBJV for an anticipated cash payment of $282.8 million due to Anadarko on March 31, 2020. In May 2017, we reached an agreement with Anadarko to settle this obligation with a cash payment to Anadarko of $37.3 million, which was equal to the estimated net present value of the obligation at March 31, 2017.
|
•
|
Dew and Pinnacle divestiture.
In July 2015, the Dew and Pinnacle systems in East Texas were sold to a third party, resulting in a net gain on sale of $77.3 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.
|
•
|
Hugoton divestiture.
In October 2016, the Hugoton system, located in Southwest Kansas and Oklahoma, was sold to a third party, resulting in a net loss on sale of
$12.0 million
recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.
|
•
|
Property exchange.
On March 17, 2017, we acquired the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and
$155.0 million
of cash consideration. We previously held a
50%
interest in, and operated, the DBJV system. The Property Exchange resulted in a net gain of
$125.7 million
recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. Results of operations attributable to the Property Exchange were included in the consolidated statements of operations beginning on the acquisition date in the first quarter of 2017.
|
•
|
Helper and Clawson divestiture
. In June 2017, the Helper and Clawson systems, located in Utah, were sold to a third party, resulting in a net gain on sale of
$16.3 million
recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2017
|
|
2016
|
|
2015
|
||||||
Total revenues and other
(1)
|
|
$
|
2,248,356
|
|
|
$
|
1,804,270
|
|
|
$
|
1,752,072
|
|
Equity income, net – affiliates
|
|
85,194
|
|
|
78,717
|
|
|
71,251
|
|
|||
Total operating expenses
(1)
|
|
1,788,549
|
|
|
1,176,408
|
|
|
1,723,017
|
|
|||
Gain (loss) on divestiture and other, net
|
|
132,388
|
|
|
(14,641
|
)
|
|
57,024
|
|
|||
Proceeds from business interruption insurance claims
(2)
|
|
29,882
|
|
|
16,270
|
|
|
—
|
|
|||
Operating income (loss)
|
|
707,271
|
|
|
708,208
|
|
|
157,330
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
|
|
(142,386
|
)
|
|
(114,921
|
)
|
|
(113,872
|
)
|
|||
Other income (expense), net
|
|
1,299
|
|
|
479
|
|
|
(619
|
)
|
|||
Income (loss) before income taxes
|
|
583,084
|
|
|
610,666
|
|
|
59,739
|
|
|||
Income tax (benefit) expense
|
|
4,866
|
|
|
8,372
|
|
|
45,532
|
|
|||
Net income (loss)
|
|
578,218
|
|
|
602,294
|
|
|
14,207
|
|
|||
Net income attributable to noncontrolling interest
|
|
10,735
|
|
|
10,963
|
|
|
10,101
|
|
|||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
567,483
|
|
|
$
|
591,331
|
|
|
$
|
4,106
|
|
Key performance metrics
(3)
|
|
|
|
|
|
|
||||||
Adjusted gross margin
|
|
$
|
1,376,478
|
|
|
$
|
1,337,443
|
|
|
$
|
1,251,047
|
|
Adjusted EBITDA
|
|
1,060,988
|
|
|
1,028,208
|
|
|
907,568
|
|
|||
Distributable cash flow
|
|
928,967
|
|
|
852,446
|
|
|
781,383
|
|
(1)
|
Revenues and other include amounts earned from services provided to our affiliates, as well as from the sale of residue 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)
|
See
Note 1—Summary of Significant Accounting Policies
in the
Notes to Consolidated Financial Statements
under
Part II
,
Item 8
of this Form
10-K
.
|
(3)
|
Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are defined under the caption
Key Performance Metrics
within this
Item 7
.
For reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, see
How We Evaluate Our Operations–Reconciliation of non-GAAP measures
within this
Item 7
.
|
|
|
Year Ended December 31,
|
|||||||||||||
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2015
|
|
Inc/
(Dec) |
|||||
Throughput for natural gas assets (MMcf/d)
|
|
|
|
|
|
|
|
|
|
|
|||||
Gathering, treating and transportation
|
|
958
|
|
|
1,537
|
|
|
(38
|
)%
|
|
1,791
|
|
|
(14
|
)%
|
Processing
|
|
2,563
|
|
|
2,350
|
|
|
9
|
%
|
|
2,331
|
|
|
1
|
%
|
Equity investment
(1)
|
|
159
|
|
|
177
|
|
|
(10
|
)%
|
|
178
|
|
|
(1
|
)%
|
Total throughput for natural gas assets
|
|
3,680
|
|
|
4,064
|
|
|
(9
|
)%
|
|
4,300
|
|
|
(5
|
)%
|
Throughput attributable to noncontrolling interest for natural gas assets
|
|
105
|
|
|
124
|
|
|
(15
|
)%
|
|
142
|
|
|
(13
|
)%
|
Total throughput attributable to Western Gas Partners, LP for natural gas assets
|
|
3,575
|
|
|
3,940
|
|
|
(9
|
)%
|
|
4,158
|
|
|
(5
|
)%
|
Throughput for crude oil, NGL and produced water assets (MBbls/d)
|
|
|
|
|
|
|
|
|
|
|
|||||
Gathering, treating, transportation and disposal
|
|
71
|
|
|
57
|
|
|
25
|
%
|
|
69
|
|
|
(17
|
)%
|
Equity investment
(2)
|
|
130
|
|
|
127
|
|
|
2
|
%
|
|
117
|
|
|
9
|
%
|
Total throughput for crude oil, NGL and produced water assets
|
|
201
|
|
|
184
|
|
|
9
|
%
|
|
186
|
|
|
(1
|
)%
|
(1)
|
Represents our 14.81% share of average Fort Union throughput and 22% share of average Rendezvous throughput.
|
(2)
|
Represents our 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEG and TEP throughput, and 33.33% share of average FRP throughput.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2015
|
|
Inc/
(Dec)
|
||||||||
Gathering, processing, transportation and disposal revenues
|
|
$
|
1,237,949
|
|
|
$
|
1,227,849
|
|
|
1
|
%
|
|
$
|
1,128,838
|
|
|
9
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages and per-unit amounts
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2015
|
|
Inc/
(Dec)
|
||||||||
Natural gas sales
(1)
|
|
$
|
382,303
|
|
|
$
|
230,366
|
|
|
66
|
%
|
|
$
|
242,826
|
|
|
(5
|
)%
|
Natural gas liquids sales
(1)
|
|
607,630
|
|
|
341,947
|
|
|
78
|
%
|
|
375,123
|
|
|
(9
|
)%
|
|||
Total
|
|
$
|
989,933
|
|
|
$
|
572,313
|
|
|
73
|
%
|
|
$
|
617,949
|
|
|
(7
|
)%
|
Average price per unit
(1)
:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas (per Mcf)
|
|
$
|
2.92
|
|
|
$
|
2.51
|
|
|
16
|
%
|
|
$
|
3.28
|
|
|
(23
|
)%
|
Natural gas liquids (per Bbl)
|
|
23.24
|
|
|
19.96
|
|
|
16
|
%
|
|
22.38
|
|
|
(11
|
)%
|
(1)
|
Excludes amounts considered above market with respect to our swap agreements for the MGR assets, DJ Basin complex and Hugoton system (until its divestiture in October 2016) that were recorded as capital contributions in the consolidated statements of equity and partners’ capital. 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
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2015
|
|
Inc/
(Dec)
|
|||||||
Other revenues
|
|
$
|
20,474
|
|
|
$
|
4,108
|
|
|
NM
|
|
$
|
5,285
|
|
|
(22
|
)%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2015
|
|
Inc/
(Dec)
|
||||||||
Equity income, net – affiliates
|
|
$
|
85,194
|
|
|
$
|
78,717
|
|
|
8
|
%
|
|
$
|
71,251
|
|
|
10
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2015
|
|
Inc/
(Dec)
|
||||||||
NGL purchases
(1)
|
|
$
|
527,298
|
|
|
$
|
238,660
|
|
|
121
|
%
|
|
$
|
251,222
|
|
|
(5
|
)%
|
Residue purchases
(1)
|
|
357,395
|
|
|
231,722
|
|
|
54
|
%
|
|
253,619
|
|
|
(9
|
)%
|
|||
Other
|
|
24,000
|
|
|
23,812
|
|
|
1
|
%
|
|
23,528
|
|
|
1
|
%
|
|||
Cost of product
|
|
908,693
|
|
|
494,194
|
|
|
84
|
%
|
|
528,369
|
|
|
(6
|
)%
|
|||
Operation and maintenance
|
|
315,994
|
|
|
308,010
|
|
|
3
|
%
|
|
331,972
|
|
|
(7
|
)%
|
|||
Total cost of product and operation and maintenance expenses
|
|
$
|
1,224,687
|
|
|
$
|
802,204
|
|
|
53
|
%
|
|
$
|
860,341
|
|
|
(7
|
)%
|
(1)
|
Excludes amounts considered above market with respect to our swap agreements for the MGR assets, DJ Basin complex and Hugoton system (until its divestiture in October 2016) that were recorded as capital contributions in the consolidated statements of equity and partners’ capital. 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
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2015
|
|
Inc/
(Dec)
|
||||||||
General and administrative
|
|
$
|
47,796
|
|
|
$
|
45,591
|
|
|
5
|
%
|
|
$
|
41,319
|
|
|
10
|
%
|
Property and other taxes
|
|
46,818
|
|
|
40,145
|
|
|
17
|
%
|
|
33,288
|
|
|
21
|
%
|
|||
Depreciation and amortization
|
|
290,874
|
|
|
272,933
|
|
|
7
|
%
|
|
272,611
|
|
|
—
|
%
|
|||
Impairments
|
|
178,374
|
|
|
15,535
|
|
|
NM
|
|
|
515,458
|
|
|
(97
|
)%
|
|||
Total other operating expenses
|
|
$
|
563,862
|
|
|
$
|
374,204
|
|
|
51
|
%
|
|
$
|
862,676
|
|
|
(57
|
)%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2015
|
|
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
|
|
$
|
(142,525
|
)
|
|
$
|
(121,832
|
)
|
|
17
|
%
|
|
$
|
(102,058
|
)
|
|
19
|
%
|
Amortization of debt issuance costs and commitment fees
|
|
(6,616
|
)
|
|
(6,398
|
)
|
|
3
|
%
|
|
(5,734
|
)
|
|
12
|
%
|
|||
Capitalized interest
|
|
6,826
|
|
|
5,562
|
|
|
23
|
%
|
|
8,318
|
|
|
(33
|
)%
|
|||
Affiliates
|
|
|
|
|
|
|
|
|
|
|
||||||||
Deferred purchase price obligation – Anadarko
(1)
|
|
(71
|
)
|
|
7,747
|
|
|
(101
|
)%
|
|
(14,398
|
)
|
|
(154
|
)%
|
|||
Interest expense
|
|
$
|
(142,386
|
)
|
|
$
|
(114,921
|
)
|
|
24
|
%
|
|
$
|
(113,872
|
)
|
|
1
|
%
|
(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 Deferred purchase price obligation - Anadarko.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2017
|
|
2016
|
|
Inc/
(Dec) |
|
2015
|
|
Inc/
(Dec)
|
||||||||
Income (loss) before income taxes
|
|
$
|
583,084
|
|
|
$
|
610,666
|
|
|
(5
|
)%
|
|
$
|
59,739
|
|
|
NM
|
|
Income tax (benefit) expense
|
|
4,866
|
|
|
8,372
|
|
|
(42
|
)%
|
|
45,532
|
|
|
(82
|
)%
|
|||
Effective tax rate
|
|
1
|
%
|
|
1
|
%
|
|
|
|
|
76
|
%
|
|
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages and per-unit amounts
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2015
|
|
Inc/
(Dec)
|
||||||||
Adjusted gross margin for natural gas assets
(1)
|
|
$
|
1,222,632
|
|
|
$
|
1,194,877
|
|
|
2
|
%
|
|
$
|
1,119,555
|
|
|
7
|
%
|
Adjusted gross margin for crude oil, NGL and produced water assets
(2)
|
|
153,846
|
|
|
142,566
|
|
|
8
|
%
|
|
131,492
|
|
|
8
|
%
|
|||
Adjusted gross margin
(3)
|
|
1,376,478
|
|
|
1,337,443
|
|
|
3
|
%
|
|
1,251,047
|
|
|
7
|
%
|
|||
Adjusted gross margin per Mcf for natural gas assets
(4)
|
|
0.94
|
|
|
0.83
|
|
|
13
|
%
|
|
0.74
|
|
|
12
|
%
|
|||
Adjusted gross margin per Bbl for crude oil, NGL and produced water assets
(5)
|
|
2.10
|
|
|
2.11
|
|
|
—
|
%
|
|
1.93
|
|
|
9
|
%
|
|||
Adjusted EBITDA
(3)
|
|
1,060,988
|
|
|
1,028,208
|
|
|
3
|
%
|
|
907,568
|
|
|
13
|
%
|
|||
Distributable cash flow
(3)
|
|
928,967
|
|
|
852,446
|
|
|
9
|
%
|
|
781,383
|
|
|
9
|
%
|
(1)
|
Adjusted gross margin 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 for natural gas assets to its most comparable GAAP measure under
How We Evaluate Our Operations—Reconciliation of non-GAAP measures
within this Item 7.
|
(2)
|
Adjusted gross margin for crude oil, NGL and produced water assets is calculated as total revenues and other for crude oil, NGL and produced water assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for crude oil, NGL and produced water 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 oil, NGL and produced water assets to its most comparable GAAP measure under
How We Evaluate Our Operations—Reconciliation of non-GAAP measures
within this Item 7.
|
(3)
|
For a reconciliation of Adjusted gross margin, Adjusted EBITDA 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 of non-GAAP measures
within this Item 7.
|
(4)
|
Average for period. Calculated as Adjusted gross margin 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 oil, NGL and produced water assets, divided by total throughput (MBbls/d) for crude oil, NGL and produced water 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
|
|
2017
|
|
2016
|
|
2015
|
||||||
Acquisitions
|
|
$
|
159,208
|
|
|
$
|
716,465
|
|
|
$
|
14,417
|
|
|
|
|
|
|
|
|
||||||
Expansion capital expenditures
|
|
$
|
623,674
|
|
|
$
|
410,221
|
|
|
$
|
583,282
|
|
Maintenance capital expenditures
|
|
49,964
|
|
|
63,637
|
|
|
54,221
|
|
|||
Total capital expenditures
(1) (2)
|
|
$
|
673,638
|
|
|
$
|
473,858
|
|
|
$
|
637,503
|
|
|
|
|
|
|
|
|
||||||
Capital incurred
(2)
|
|
$
|
798,694
|
|
|
$
|
491,349
|
|
|
$
|
566,045
|
|
(1)
|
Capital expenditures for the years ended December 31,
2017
,
2016
and
2015
, are presented net of
$1.4 million
,
$6.1 million
and
$0.5 million
, respectively, of contributions in aid of construction costs from affiliates.
|
(2)
|
For the years ended December 31,
2017
,
2016
and
2015
, included
$6.8 million
,
$5.6 million
and
$8.3 million
, respectively, of capitalized interest.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2017
|
|
2016
|
|
2015
|
||||||
Net cash provided by (used in):
|
|
|
|
|
|
|
||||||
Operating activities
|
|
$
|
901,495
|
|
|
$
|
917,585
|
|
|
$
|
785,645
|
|
Investing activities
|
|
(763,604
|
)
|
|
(1,105,534
|
)
|
|
(500,277
|
)
|
|||
Financing activities
|
|
(417,002
|
)
|
|
447,841
|
|
|
(254,389
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
|
$
|
(279,111
|
)
|
|
$
|
259,892
|
|
|
$
|
30,979
|
|
•
|
$673.6 million
of capital expenditures, net of
$1.4 million
of contributions in aid of construction costs from affiliates, primarily related to construction and expansion at the DBJV system and the DBM and DJ Basin complexes and the construction of the DBM water systems;
|
•
|
$155.3 million of cash consideration paid as part of the Property Exchange;
|
•
|
$23.3 million of net proceeds from the sale of the Helper and Clawson systems in Utah;
|
•
|
$23.1 million
of distributions from equity investments in excess of cumulative earnings;
|
•
|
$23.0 million
of proceeds from property insurance claims attributable to the DBM outage; and
|
•
|
$3.9 million
of cash paid for equipment purchases from Anadarko.
|
•
|
$712.5 million of cash paid for the acquisition of Springfield;
|
•
|
$473.9 million
of capital expenditures, net of
$6.1 million
of contributions in aid of construction costs from affiliates, primarily related to plant construction and expansion at the DBM and DJ Basin complexes and the DBJV system;
|
•
|
$45.1 million of net proceeds from the sale of the Hugoton system in Southwest Kansas and Oklahoma;
|
•
|
$21.2 million
of distributions from equity investments in excess of cumulative earnings;
|
•
|
$17.5 million
of proceeds from property insurance claims attributable to the DBM outage; and
|
•
|
$4.0 million
of cash paid for equipment purchases from Anadarko.
|
•
|
$637.5 million of capital expenditures, net of $0.5 million of contributions in aid of construction costs from affiliates, primarily related to the construction of Train IV at the DBM complex, continued construction of Lancaster Train II (within the DJ Basin complex) and expansion at the DBJV system;
|
•
|
$145.6 million of net proceeds from the sale of the Dew and Pinnacle systems in East Texas;
|
•
|
$16.2 million of distributions from equity investments in excess of cumulative earnings;
|
•
|
$11.4 million of cash contributed to equity investments, primarily related to expansion projects at White Cliffs, TEP and FRP;
|
•
|
$10.9 million of cash paid for equipment purchases from Anadarko; and
|
•
|
$3.5 million of cash paid for post-closing purchase price adjustments related to the DBM acquisition.
|
•
|
$801.3 million
of distributions paid to our unitholders;
|
•
|
$370.0 million
of borrowings under the RCF, which were used for general partnership purposes, including funding of capital expenditures;
|
•
|
$58.6 million
of capital contributions from Anadarko related to the above-market component of swap agreements;
|
•
|
$37.3 million
of cash paid to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko; and
|
•
|
$13.6 million
of distributions paid to the noncontrolling interest owner of Chipeta.
|
•
|
$900.0 million
of repayments of outstanding borrowings under the RCF;
|
•
|
$671.9 million
of distributions paid to our unitholders;
|
•
|
$599.3 million of borrowings under the RCF, net of extension costs, which were used to fund a portion of the Springfield acquisition and for general partnership purposes, including funding capital expenditures;
|
•
|
$494.6 million of net proceeds from the 2026 Notes offering in July 2016, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of the outstanding borrowings under the RCF;
|
•
|
$440.0 million of net proceeds from the issuance of 14,030,611 Series A Preferred units in March 2016, all of which was used to fund a portion of the acquisition of Springfield;
|
•
|
$246.9 million of net proceeds from the issuance of 7,892,220 Series A Preferred units in April 2016, all of which was used to pay down amounts borrowed under the RCF in connection with the acquisition of Springfield;
|
•
|
$203.3 million of net proceeds from the offering of the additional 2044 Notes in October 2016, after underwriting discounts and original issue premium and offering costs, all of which was used to repay amounts then outstanding under the RCF and for general partnership purposes, including capital expenditures;
|
•
|
$45.8 million
of capital contributions from Anadarko related to the above-market component of swap agreements;
|
•
|
$25.0 million of net proceeds from the sale of common units to WGP, all of which was used to fund a portion of the acquisition of Springfield;
|
•
|
$23.5 million
of net distributions paid to Anadarko representing pre-acquisition intercompany transactions attributable to Springfield; and
|
•
|
$13.8 million
of distributions paid to the noncontrolling interest owner of Chipeta.
|
•
|
$610.0 million of repayments of outstanding borrowings under the RCF;
|
•
|
$545.1 million of distributions paid to our unitholders;
|
•
|
$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 the RCF;
|
•
|
$400.0 million of borrowings under the RCF, which were used for general partnership purposes, including funding capital expenditures;
|
•
|
$57.4 million of net proceeds from sales of common units under the registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of $500.0 million of our common units. Net proceeds were used for general partnership purposes, including funding capital expenditures;
|
•
|
$49.8 million of net distributions paid to Anadarko representing pre-acquisition intercompany transactions attributable to Springfield and DBJV;
|
•
|
$18.4 million of capital contribution from Anadarko related to the above-market component of swap agreements; and
|
•
|
$12.2 million of distributions paid to the noncontrolling interest owner of Chipeta.
|
|
|
Obligations by Period
|
||||||||||||||||||||||||||
thousands
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
|
Total
|
||||||||||||||
Long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Principal
|
|
$
|
350,000
|
|
|
$
|
—
|
|
|
$
|
370,000
|
|
|
$
|
500,000
|
|
|
$
|
670,000
|
|
|
$
|
1,600,000
|
|
|
$
|
3,490,000
|
|
Interest
|
|
145,793
|
|
|
140,141
|
|
|
131,115
|
|
|
112,727
|
|
|
102,327
|
|
|
832,319
|
|
|
1,464,422
|
|
|||||||
Asset retirement obligations
|
|
2,304
|
|
|
—
|
|
|
2,554
|
|
|
—
|
|
|
—
|
|
|
140,840
|
|
|
145,698
|
|
|||||||
Capital expenditures
|
|
212,463
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
212,463
|
|
|||||||
Credit facility fees
|
|
2,400
|
|
|
2,400
|
|
|
375
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,175
|
|
|||||||
Environmental obligations
|
|
833
|
|
|
323
|
|
|
323
|
|
|
141
|
|
|
141
|
|
|
57
|
|
|
1,818
|
|
|||||||
Operating leases
|
|
8,402
|
|
|
7,506
|
|
|
1,615
|
|
|
460
|
|
|
467
|
|
|
2,021
|
|
|
20,471
|
|
|||||||
Total
|
|
$
|
722,195
|
|
|
$
|
150,370
|
|
|
$
|
505,982
|
|
|
$
|
613,328
|
|
|
$
|
772,935
|
|
|
$
|
2,575,237
|
|
|
$
|
5,340,047
|
|
•
|
significant changes in our unit price;
|
•
|
significant declines in commodity prices;
|
•
|
significant increases in operating and capital costs;
|
•
|
impairments recognized;
|
•
|
acquisitions and disposals of assets;
|
•
|
changes in throughput; and
|
•
|
significant declines in trading multiples for our peers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Benjamin M. Fink
|
|
Benjamin M. Fink
President and Chief Executive Officer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
|
|
|
/s/ Jaime R. Casas
|
|
Jaime R. Casas
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
|
|
2017
|
|
2016
|
|
2015
|
||||||
Revenues and other – affiliates
|
|
|
|
|
|
|
||||||
Gathering, processing, transportation and disposal
|
|
$
|
656,795
|
|
|
$
|
750,087
|
|
|
$
|
772,361
|
|
Natural gas and natural gas liquids sales
|
|
692,447
|
|
|
478,145
|
|
|
447,106
|
|
|||
Other
|
|
16,076
|
|
|
—
|
|
|
1,172
|
|
|||
Total revenues and other – affiliates
|
|
1,365,318
|
|
|
1,228,232
|
|
|
1,220,639
|
|
|||
Revenues and other – third parties
|
|
|
|
|
|
|
||||||
Gathering, processing, transportation and disposal
|
|
581,154
|
|
|
477,762
|
|
|
356,477
|
|
|||
Natural gas and natural gas liquids sales
|
|
297,486
|
|
|
94,168
|
|
|
170,843
|
|
|||
Other
|
|
4,398
|
|
|
4,108
|
|
|
4,113
|
|
|||
Total revenues and other – third parties
|
|
883,038
|
|
|
576,038
|
|
|
531,433
|
|
|||
Total revenues and other
|
|
2,248,356
|
|
|
1,804,270
|
|
|
1,752,072
|
|
|||
Equity income, net – affiliates
|
|
85,194
|
|
|
78,717
|
|
|
71,251
|
|
|||
Operating expenses
|
|
|
|
|
|
|
||||||
Cost of product
(1)
|
|
908,693
|
|
|
494,194
|
|
|
528,369
|
|
|||
Operation and maintenance
(1)
|
|
315,994
|
|
|
308,010
|
|
|
331,972
|
|
|||
General and administrative
(1)
|
|
47,796
|
|
|
45,591
|
|
|
41,319
|
|
|||
Property and other taxes
|
|
46,818
|
|
|
40,145
|
|
|
33,288
|
|
|||
Depreciation and amortization
|
|
290,874
|
|
|
272,933
|
|
|
272,611
|
|
|||
Impairments
|
|
178,374
|
|
|
15,535
|
|
|
515,458
|
|
|||
Total operating expenses
|
|
1,788,549
|
|
|
1,176,408
|
|
|
1,723,017
|
|
|||
Gain (loss) on divestiture and other, net
(2)
|
|
132,388
|
|
|
(14,641
|
)
|
|
57,024
|
|
|||
Proceeds from business interruption insurance claims
|
|
29,882
|
|
|
16,270
|
|
|
—
|
|
|||
Operating income (loss)
|
|
707,271
|
|
|
708,208
|
|
|
157,330
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
(3)
|
|
(142,386
|
)
|
|
(114,921
|
)
|
|
(113,872
|
)
|
|||
Other income (expense), net
|
|
1,299
|
|
|
479
|
|
|
(619
|
)
|
|||
Income (loss) before income taxes
|
|
583,084
|
|
|
610,666
|
|
|
59,739
|
|
|||
Income tax (benefit) expense
|
|
4,866
|
|
|
8,372
|
|
|
45,532
|
|
|||
Net income (loss)
|
|
578,218
|
|
|
602,294
|
|
|
14,207
|
|
|||
Net income attributable to noncontrolling interest
|
|
10,735
|
|
|
10,963
|
|
|
10,101
|
|
|||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
567,483
|
|
|
$
|
591,331
|
|
|
$
|
4,106
|
|
Limited partners’ interest in net income (loss):
|
|
|
|
|
|
|
||||||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
567,483
|
|
|
$
|
591,331
|
|
|
$
|
4,106
|
|
Pre-acquisition net (income) loss allocated to Anadarko
|
|
—
|
|
|
(11,326
|
)
|
|
(79,386
|
)
|
|||
Series A Preferred units interest in net (income) loss
|
|
(42,373
|
)
|
|
(76,893
|
)
|
|
—
|
|
|||
General partner interest in net (income) loss
(4)
|
|
(303,835
|
)
|
|
(236,561
|
)
|
|
(180,996
|
)
|
|||
Common and Class C limited partners’ interest in net income (loss)
(4)
|
|
221,275
|
|
|
266,551
|
|
|
(256,276
|
)
|
|||
Net income (loss) per common unit – basic and diluted
(5)
|
|
$
|
1.30
|
|
|
$
|
1.74
|
|
|
$
|
(1.95
|
)
|
(1)
|
Cost of product includes product purchases from Anadarko (as defined in
Note 1
) of
$86.0 million
,
$80.5 million
and
$167.4 million
for the
years ended December 31, 2017
,
2016
and
2015
, respectively. Operation and maintenance includes charges from Anadarko of
$72.5 million
,
$72.3 million
and
$77.1 million
for the
years ended December 31, 2017
,
2016
and
2015
, respectively. General and administrative includes charges from Anadarko of
$39.1 million
,
$38.1 million
and
$33.9 million
for the
years ended December 31, 2017
,
2016
and
2015
, respectively. See
Note 5
.
|
(2)
|
Includes losses related to an incident at the DBM complex for the years ended December 31, 2017 and 2015. See
Note 1
.
|
(3)
|
Includes affiliate (as defined in
Note 1
) amounts of
$(0.1) million
,
$7.7 million
and
$(14.4) million
for the
years ended December 31, 2017
,
2016
and
2015
, respectively. See
Note 2
and
Note 12
.
|
(4)
|
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
.
|
(5)
|
See
Note 4
for the calculation of net income (loss) per common unit.
|
|
|
December 31,
|
||||||
thousands except number of units
|
|
2017
|
|
2016
|
||||
ASSETS
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
78,814
|
|
|
$
|
357,925
|
|
Accounts receivable, net
(1)
|
|
160,432
|
|
|
223,223
|
|
||
Other current assets
|
|
14,816
|
|
|
12,866
|
|
||
Total current assets
|
|
254,062
|
|
|
594,014
|
|
||
Note receivable – Anadarko
|
|
260,000
|
|
|
260,000
|
|
||
Property, plant and equipment
|
|
|
|
|
||||
Cost
|
|
7,871,102
|
|
|
6,861,942
|
|
||
Less accumulated depreciation
|
|
2,140,211
|
|
|
1,812,010
|
|
||
Net property, plant and equipment
|
|
5,730,891
|
|
|
5,049,932
|
|
||
Goodwill
|
|
416,160
|
|
|
417,610
|
|
||
Other intangible assets
|
|
775,269
|
|
|
803,698
|
|
||
Equity investments
|
|
566,211
|
|
|
594,208
|
|
||
Other assets
|
|
11,757
|
|
|
13,566
|
|
||
Total assets
|
|
$
|
8,014,350
|
|
|
$
|
7,733,028
|
|
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accounts and imbalance payables
(2)
|
|
$
|
349,801
|
|
|
$
|
247,076
|
|
Accrued ad valorem taxes
|
|
26,633
|
|
|
23,121
|
|
||
Accrued liabilities
(3)
|
|
47,899
|
|
|
45,108
|
|
||
Total current liabilities
|
|
424,333
|
|
|
315,305
|
|
||
Long-term debt
|
|
3,464,712
|
|
|
3,091,461
|
|
||
Deferred income taxes
|
|
7,409
|
|
|
6,402
|
|
||
Asset retirement obligations and other
|
|
146,885
|
|
|
142,641
|
|
||
Deferred purchase price obligation – Anadarko
(4)
|
|
—
|
|
|
41,440
|
|
||
Total long-term liabilities
|
|
3,619,006
|
|
|
3,281,944
|
|
||
Total liabilities
|
|
4,043,339
|
|
|
3,597,249
|
|
||
Equity and partners’ capital
|
|
|
|
|
||||
Series A Preferred units (zero and 21,922,831 units issued and outstanding at December 31, 2017 and 2016, respectively)
(5)
|
|
—
|
|
|
639,545
|
|
||
Common units (152,602,105 and 130,671,970 units issued and outstanding at December 31, 2017 and 2016, respectively)
|
|
2,950,010
|
|
|
2,536,872
|
|
||
Class C units (13,243,883 and 12,358,123 units issued and outstanding at December 31, 2017 and 2016, respectively)
(6)
|
|
780,040
|
|
|
750,831
|
|
||
General partner units (2,583,068 units issued and outstanding at December 31, 2017 and 2016)
|
|
179,232
|
|
|
143,968
|
|
||
Total partners’ capital
|
|
3,909,282
|
|
|
4,071,216
|
|
||
Noncontrolling interest
|
|
61,729
|
|
|
64,563
|
|
||
Total equity and partners’ capital
|
|
3,971,011
|
|
|
4,135,779
|
|
||
Total liabilities, equity and partners’ capital
|
|
$
|
8,014,350
|
|
|
$
|
7,733,028
|
|
(1)
|
Accounts receivable, net includes amounts receivable from affiliates (as defined in
Note 1
) of
$36.3 million
and
$76.6 million
as of
December 31, 2017
and
2016
, respectively. Accounts receivable, net as of December 31,
2016
, also includes an insurance claim receivable related to an incident at the DBM complex. See
Note 1
.
|
(2)
|
Accounts and imbalance payables includes affiliate amounts of
$0.3 million
and
zero
as of
December 31, 2017
and
2016
, respectively.
|
(3)
|
Accrued liabilities includes affiliate amounts of
$0.2 million
and
zero
as of
December 31, 2017
and
2016
, respectively.
|
(4)
|
See
Note 2
.
|
(5)
|
The Series A Preferred units converted into common units on a
one
-for-one basis in 2017. See
Note 4
.
|
(6)
|
The Class C units will convert into common units on a
one
-for-one basis on March 1, 2020, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date. See
Note 4
.
|
|
|
Partners’ Capital
|
|
|
|
|
||||||||||||||||||||||
thousands
|
|
Net
Investment
by Anadarko
|
|
Common
Units
|
|
Class C
Units
|
|
Series A Preferred Units
|
|
General
Partner
Units
|
|
Noncontrolling
Interest
|
|
Total
|
||||||||||||||
Balance at December 31, 2014
|
|
$
|
556,596
|
|
|
$
|
3,119,714
|
|
|
$
|
716,957
|
|
|
$
|
—
|
|
|
$
|
105,725
|
|
|
$
|
69,470
|
|
|
$
|
4,568,462
|
|
Net income (loss)
|
|
79,386
|
|
|
(238,166
|
)
|
|
(18,110
|
)
|
|
—
|
|
|
180,996
|
|
|
10,101
|
|
|
14,207
|
|
|||||||
Above-market component of swap agreements with Anadarko
(1)
|
|
—
|
|
|
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
|
|
—
|
|
|
3,480
|
|
|
—
|
|
|
—
|
|
|
71
|
|
|
—
|
|
|
3,551
|
|
|||||||
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
(49,801
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(49,801
|
)
|
|||||||
Net contributions from (distributions to) Anadarko of other assets
|
|
—
|
|
|
(4,547
|
)
|
|
—
|
|
|
—
|
|
|
(85
|
)
|
|
—
|
|
|
(4,632
|
)
|
|||||||
Elimination of net deferred tax liabilities
|
|
41,844
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
41,844
|
|
|||||||
Other
|
|
135
|
|
|
68
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
201
|
|
|||||||
Balance at December 31, 2015
|
|
$
|
430,598
|
|
|
$
|
2,588,991
|
|
|
$
|
710,891
|
|
|
$
|
—
|
|
|
$
|
120,164
|
|
|
$
|
67,384
|
|
|
$
|
3,918,028
|
|
Net income (loss)
|
|
11,326
|
|
|
269,018
|
|
|
28,642
|
|
|
45,784
|
|
|
236,561
|
|
|
10,963
|
|
|
602,294
|
|
|||||||
Above-market component of swap agreements with Anadarko
(1)
|
|
—
|
|
|
45,820
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
45,820
|
|
|||||||
Issuance of common units, net of offering expenses
|
|
—
|
|
|
25,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25,000
|
|
|||||||
Issuance of Series A Preferred units, net of offering expenses
|
|
—
|
|
|
—
|
|
|
—
|
|
|
686,937
|
|
|
—
|
|
|
—
|
|
|
686,937
|
|
|||||||
Beneficial conversion feature of Series A Preferred units
|
|
—
|
|
|
93,409
|
|
|
—
|
|
|
(93,409
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Amortization of beneficial conversion feature of Class C units and Series A Preferred units
|
|
—
|
|
|
(42,407
|
)
|
|
11,298
|
|
|
31,109
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Distributions to noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13,784
|
)
|
|
(13,784
|
)
|
|||||||
Distributions to unitholders
|
|
—
|
|
|
(428,231
|
)
|
|
—
|
|
|
(30,876
|
)
|
|
(212,831
|
)
|
|
—
|
|
|
(671,938
|
)
|
|||||||
Acquisitions from affiliates
|
|
(553,833
|
)
|
|
(158,667
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(712,500
|
)
|
|||||||
Revision to Deferred purchase price obligation – Anadarko
(2)
|
|
—
|
|
|
139,487
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
139,487
|
|
|||||||
Contributions of equity-based compensation from Anadarko
|
|
—
|
|
|
4,131
|
|
|
—
|
|
|
—
|
|
|
83
|
|
|
—
|
|
|
4,214
|
|
|||||||
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
(23,491
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(23,491
|
)
|
|||||||
Net contributions from (distributions to) Anadarko of other assets
|
|
—
|
|
|
(572
|
)
|
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
—
|
|
|
(581
|
)
|
|||||||
Elimination of net deferred tax liabilities
|
|
135,400
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
135,400
|
|
|||||||
Other
|
|
—
|
|
|
893
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
893
|
|
|||||||
Balance at December 31, 2016
|
|
$
|
—
|
|
|
$
|
2,536,872
|
|
|
$
|
750,831
|
|
|
$
|
639,545
|
|
|
$
|
143,968
|
|
|
$
|
64,563
|
|
|
$
|
4,135,779
|
|
Net income (loss)
|
|
—
|
|
|
231,405
|
|
|
24,790
|
|
|
7,453
|
|
|
303,835
|
|
|
10,735
|
|
|
578,218
|
|
|||||||
Above-market component of swap agreements with Anadarko
(1)
|
|
—
|
|
|
58,551
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
58,551
|
|
|||||||
Conversion of Series A Preferred units into common units
(3)
|
|
—
|
|
|
686,936
|
|
|
—
|
|
|
(686,936
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Amortization of beneficial conversion feature of Class C units and Series A Preferred units
|
|
—
|
|
|
(66,718
|
)
|
|
4,419
|
|
|
62,299
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Distributions to noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13,569
|
)
|
|
(13,569
|
)
|
|||||||
Distributions to unitholders
|
|
—
|
|
|
(510,228
|
)
|
|
—
|
|
|
(22,361
|
)
|
|
(268,711
|
)
|
|
—
|
|
|
(801,300
|
)
|
|||||||
Acquisitions from affiliates
|
|
(1,263
|
)
|
|
1,263
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Revision to Deferred purchase price obligation – Anadarko
(2)
|
|
—
|
|
|
4,165
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,165
|
|
|||||||
Contributions of equity-based compensation from Anadarko
|
|
—
|
|
|
4,473
|
|
|
—
|
|
|
—
|
|
|
90
|
|
|
—
|
|
|
4,563
|
|
|||||||
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
1,263
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,263
|
|
|||||||
Net contributions from (distributions to) Anadarko of other assets
|
|
—
|
|
|
3,139
|
|
|
—
|
|
|
—
|
|
|
50
|
|
|
—
|
|
|
3,189
|
|
|||||||
Other
|
|
—
|
|
|
152
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
152
|
|
|||||||
Balance at December 31, 2017
|
|
$
|
—
|
|
|
$
|
2,950,010
|
|
|
$
|
780,040
|
|
|
$
|
—
|
|
|
$
|
179,232
|
|
|
$
|
61,729
|
|
|
$
|
3,971,011
|
|
(1)
|
See
Note 5
.
|
(2)
|
See
Note 2
.
|
(3)
|
See
Note 4
.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2017
|
|
2016
|
|
2015
|
||||||
Cash flows from operating activities
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
578,218
|
|
|
$
|
602,294
|
|
|
$
|
14,207
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
Depreciation and amortization
|
|
290,874
|
|
|
272,933
|
|
|
272,611
|
|
|||
Impairments
|
|
178,374
|
|
|
15,535
|
|
|
515,458
|
|
|||
Non-cash equity-based compensation expense
|
|
4,922
|
|
|
4,735
|
|
|
4,188
|
|
|||
Deferred income taxes
|
|
2,458
|
|
|
2,555
|
|
|
11,346
|
|
|||
Accretion and amortization of long-term obligations, net
|
|
4,254
|
|
|
(3,789
|
)
|
|
17,698
|
|
|||
Equity income, net – affiliates
|
|
(85,194
|
)
|
|
(78,717
|
)
|
|
(71,251
|
)
|
|||
Distributions from equity investment earnings – affiliates
|
|
87,380
|
|
|
82,185
|
|
|
82,054
|
|
|||
(Gain) loss on divestiture and other, net
(1)
|
|
(132,388
|
)
|
|
14,641
|
|
|
(57,024
|
)
|
|||
Lower of cost or market inventory adjustments
|
|
145
|
|
|
168
|
|
|
443
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
|
||||||
(Increase) decrease in accounts receivable, net
|
|
(16,127
|
)
|
|
(48,947
|
)
|
|
(4,371
|
)
|
|||
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net
|
|
(6,930
|
)
|
|
58,359
|
|
|
1,006
|
|
|||
Change in other items, net
|
|
(4,491
|
)
|
|
(4,367
|
)
|
|
(720
|
)
|
|||
Net cash provided by operating activities
|
|
901,495
|
|
|
917,585
|
|
|
785,645
|
|
|||
Cash flows from investing activities
|
|
|
|
|
|
|
||||||
Capital expenditures
|
|
(675,025
|
)
|
|
(479,993
|
)
|
|
(637,964
|
)
|
|||
Contributions in aid of construction costs from affiliates
|
|
1,387
|
|
|
6,135
|
|
|
461
|
|
|||
Acquisitions from affiliates
|
|
(3,910
|
)
|
|
(716,465
|
)
|
|
(10,903
|
)
|
|||
Acquisitions from third parties
|
|
(155,298
|
)
|
|
—
|
|
|
(3,514
|
)
|
|||
Investments in equity affiliates
|
|
(384
|
)
|
|
(27
|
)
|
|
(11,442
|
)
|
|||
Distributions from equity investments in excess of cumulative earnings – affiliates
|
|
23,085
|
|
|
21,238
|
|
|
16,244
|
|
|||
Proceeds from the sale of assets to affiliates
|
|
—
|
|
|
623
|
|
|
925
|
|
|||
Proceeds from the sale of assets to third parties
|
|
23,564
|
|
|
45,490
|
|
|
145,916
|
|
|||
Proceeds from property insurance claims
|
|
22,977
|
|
|
17,465
|
|
|
—
|
|
|||
Net cash used in investing activities
|
|
(763,604
|
)
|
|
(1,105,534
|
)
|
|
(500,277
|
)
|
|||
Cash flows from financing activities
|
|
|
|
|
|
|
||||||
Borrowings, net of debt issuance costs
|
|
369,989
|
|
|
1,297,218
|
|
|
889,606
|
|
|||
Repayments of debt
|
|
—
|
|
|
(900,000
|
)
|
|
(610,000
|
)
|
|||
Settlement of the Deferred purchase price obligation – Anadarko
(2)
|
|
(37,346
|
)
|
|
—
|
|
|
—
|
|
|||
Increase (decrease) in outstanding checks
|
|
5,593
|
|
|
2,079
|
|
|
(2,666
|
)
|
|||
Proceeds from the issuance of common units, net of offering expenses
|
|
(183
|
)
|
|
25,000
|
|
|
57,353
|
|
|||
Proceeds from the issuance of Series A Preferred units, net of offering expenses
|
|
—
|
|
|
686,937
|
|
|
—
|
|
|||
Distributions to unitholders
(3)
|
|
(801,300
|
)
|
|
(671,938
|
)
|
|
(545,143
|
)
|
|||
Distributions to noncontrolling interest owner
|
|
(13,569
|
)
|
|
(13,784
|
)
|
|
(12,187
|
)
|
|||
Net contributions from (distributions to) Anadarko
|
|
1,263
|
|
|
(23,491
|
)
|
|
(49,801
|
)
|
|||
Above-market component of swap agreements with Anadarko
(3)
|
|
58,551
|
|
|
45,820
|
|
|
18,449
|
|
|||
Net cash provided by (used in) financing activities
|
|
(417,002
|
)
|
|
447,841
|
|
|
(254,389
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
|
(279,111
|
)
|
|
259,892
|
|
|
30,979
|
|
|||
Cash and cash equivalents at beginning of period
|
|
357,925
|
|
|
98,033
|
|
|
67,054
|
|
|||
Cash and cash equivalents at end of period
|
|
$
|
78,814
|
|
|
$
|
357,925
|
|
|
$
|
98,033
|
|
Supplemental disclosures
|
|
|
|
|
|
|
||||||
Accretion expense and revisions to the Deferred purchase price obligation – Anadarko
(2)
|
|
$
|
(4,094
|
)
|
|
$
|
(147,234
|
)
|
|
$
|
174,276
|
|
Net distributions to (contributions from) Anadarko of other assets
(4)
|
|
(3,189
|
)
|
|
581
|
|
|
4,632
|
|
|||
Interest paid, net of capitalized interest
|
|
137,326
|
|
|
106,485
|
|
|
94,720
|
|
|||
Taxes paid (reimbursements received)
|
|
1,194
|
|
|
838
|
|
|
(138
|
)
|
|||
Accrued capital expenditures
|
|
204,309
|
|
|
79,253
|
|
|
61,454
|
|
|||
Fair value of properties and equipment from non-cash third party transactions
(2)
|
|
551,453
|
|
|
—
|
|
|
—
|
|
(1)
|
Includes losses related to an incident at the DBM complex for the years ended December 31, 2017 and 2015. See
Note 1
.
|
(2)
|
See
Note 2
.
|
(3)
|
See
Note 5
.
|
(4)
|
Includes
$(1.4) million
related to pipe and equipment purchases and
$(1.8) million
related to other assets for the year ended December 31, 2017. See
Note 5
.
|
|
|
Owned and
Operated
|
|
Operated
Interests
|
|
Non-Operated
Interests
|
|
Equity
Interests
|
||||
Gathering systems
(1)
|
|
12
|
|
|
3
|
|
|
3
|
|
|
2
|
|
Treating facilities
|
|
19
|
|
|
3
|
|
|
—
|
|
|
3
|
|
Natural gas processing plants/trains
|
|
20
|
|
|
4
|
|
|
—
|
|
|
2
|
|
NGL pipelines
|
|
2
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Natural gas pipelines
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Oil pipelines
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
(1)
|
Includes the DBM water systems.
|
|
|
Percentage Interest
|
|
Equity investments
(1)
|
|
|
|
Fort Union
|
|
14.81
|
%
|
White Cliffs
|
|
10
|
%
|
Rendezvous
|
|
22
|
%
|
Mont Belvieu JV
|
|
25
|
%
|
TEP
|
|
20
|
%
|
TEG
|
|
20
|
%
|
FRP
|
|
33.33
|
%
|
Proportionate consolidation
(2)
|
|
|
|
Marcellus Interest systems
|
|
33.75
|
%
|
Newcastle system
|
|
50
|
%
|
Springfield system
|
|
50.1
|
%
|
Full consolidation
|
|
|
|
Chipeta
(3)
|
|
75
|
%
|
DBJV system
(4)
|
|
100
|
%
|
(1)
|
Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments.
|
(2)
|
The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets.
|
(3)
|
The
25%
interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements.
|
(4)
|
The Partnership acquired an additional
50%
interest in the DBJV system (the “Additional DBJV System Interest”) from a third party on March 17, 2017. See
Note 2
.
|
•
|
Fee-based gathering / processing.
Under Topic 605, fee revenue was recognized based on the rate in effect for the month of service, even when certain fees were charged on an upfront or limited-term basis. In addition, certain contingent fees were charged and recognized only when the customer did not meet the specified delivery minimums for the completed performance period. Under Topic 606, the Partnership will recognize revenue associated with upfront or limited-term fees over the expected period of benefit. In addition, the contingent fees will be estimated and recognized as the services are performed for the customer’s delivered volumes. Differences between revenue recognized and amounts billed to customers will be recognized as contract assets or contract liabilities as appropriate. This will result in a change in the timing of revenue and changes to net income as a result of the consideration provisions. The magnitude of this change is dependent on future customer volumes subject to the impacted contracts.
|
•
|
Cost of service rate adjustments.
The Partnership receives fee revenue from contracts that require periodic rate redeterminations based upon the Partnership’s costs of service. Under Topic 605, revenue was recognized based on the amounts billed to customers each period. Management is continuing to evaluate the proper accounting for these cost of service-based rate changes under Topic 606. The final conclusion about the accounting for these rate redeterminations could impact the cumulative effect adjustment that will be recorded effective January 1, 2018.
|
•
|
Aid in construction.
Under certain midstream service contracts, the Partnership receives reimbursement for capital costs necessary to provide services to the customer (i.e., connection costs, etc.). These reimbursements historically have been reflected as a reduction to property, plant and equipment upon receipt (and a reduction to capital expenditures). Beginning in 2018, reimbursement of capital costs received from customers will be reflected as a contract liability (deferred revenue) upon receipt. The contract liability will be amortized to revenue over the expected period of benefit. The magnitude of this change to net income and to the Partnership’s capital expenditures is dependent on the amount of aid in construction reimbursements received from customers.
|
•
|
Percentage of proceeds - gathering / processing.
Under Topic 605, the Partnership recognized cost of product expense when the product was purchased from a producer to whom it provided midstream services and recognized revenue when the product was sold to a third party. Under Topic 606, in some instances where all or a percentage of the proceeds from the sale must be returned to the producer, the net margin from the purchase and sale transactions will be presented net within revenue because the Partnership is acting as the producer’s agent in the sale. While reported product sales revenue and expense will be materially reduced, these presentation changes will not impact net income. The magnitude of this change is dependent on future customer volumes subject to the impacted contracts and commodity prices for those volumes.
|
•
|
Noncash consideration - keep-whole and percentage of product agreements.
The Partnership receives noncash consideration in the form of gas and/or NGL products in exchange for services under certain midstream contracts. Under Topic 605, the Partnership recognized revenue only upon the sale of the related products. Under Topic 606, the Partnership will recognize revenue for the products received as noncash consideration in exchange for the services provided to the customer, with the keep-whole noncash consideration value based on the net value of the NGLs over the replacement residue gas. The Partnership will also recognize both revenue and cost of product expense upon sale of the related products to a different customer. Reported revenue and expense are not expected to be materially impacted by this change, and there will be no impact to net income. The magnitude of this change is dependent on future customer volumes subject to the impacted contracts and commodity prices for those volumes.
|
•
|
Wellhead purchase / sale incorporated into gathering / processing.
Under Topic 605, the gas purchase cost was recognized as cost of product expense and any specified gathering or processing fees charged to the producer were recognized as revenue. Under Topic 606, the fees charged to the contract counterparty are recognized as adjustments to the purchase cost instead of revenue when such fees relate to services performed after control of the product transfers to the Partnership. While there is no impact to net income, it will result in decreased revenue and cost of product expense. The magnitude of this change is dependent on future customer volumes subject to the impacted contracts.
|
thousands except unit and percent amounts
|
|
Acquisition
Date
|
|
Percentage
Acquired |
|
Borrowings
|
|
Cash
On Hand
|
|
Common Units
Issued
|
|
Series A
Preferred Units Issued
|
|||||||
DBJV system
(1)
|
|
03/02/2015
|
|
50
|
%
|
|
$
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
—
|
|
Springfield system
(2)
|
|
03/14/2016
|
|
50.1
|
%
|
|
247,500
|
|
|
—
|
|
|
2,089,602
|
|
|
14,030,611
|
|
||
DBJV system
(3)
|
|
03/17/2017
|
|
50
|
%
|
|
—
|
|
|
155,000
|
|
|
—
|
|
|
—
|
|
(1)
|
The Partnership acquired Delaware Basin JV Gathering LLC (“DBJV”) from Anadarko. At the time of acquisition, DBJV owned a 50% interest in a gathering system and related facilities (the “DBJV system”) located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. At the acquisition date, the Partnership estimated the future payment would be
$282.8 million
, the estimated net present value of which was
$174.3 million
. For further information, see
DBJV acquisition—deferred purchase price obligation - Anadarko
below.
|
(2)
|
The Partnership acquired Springfield Pipeline LLC (“Springfield”) from Anadarko for
$750.0 million
, consisting of
$712.5 million
in cash and the issuance of
1,253,761
of the Partnership’s common units. Springfield owns a
50.1%
interest in an oil gathering system and a gas gathering system. The Springfield oil and gas gathering systems (collectively, the “Springfield system”) are located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. The Partnership financed the cash portion of the acquisition through: (i) borrowings of
$247.5 million
on the Partnership’s senior unsecured revolving credit facility (“RCF”), (ii) the issuance of
835,841
of the Partnership’s common units to WGP and (iii) the issuance of Series A Preferred units to private investors. See
Note 4
for further information regarding the Series A Preferred units.
|
(3)
|
The Partnership acquired the Additional DBJV System Interest from a third party. See
Property exchange
below.
|
|
|
Deferred purchase price obligation - Anadarko
|
|
Estimated future payment obligation
(1)
|
||||
Balance at December 31, 2015
|
|
$
|
188,674
|
|
|
$
|
282,807
|
|
Accretion revision
(2)
|
|
(7,747
|
)
|
|
|
|||
Revision to Deferred purchase price obligation – Anadarko
(3)
|
|
(139,487
|
)
|
|
|
|||
Balance at December 31, 2016
|
|
41,440
|
|
|
56,455
|
|
||
Accretion expense
(4)
|
|
71
|
|
|
|
|||
Revision to Deferred purchase price obligation – Anadarko
(3)
|
|
(4,165
|
)
|
|
|
|||
Settlement of the Deferred purchase price obligation – Anadarko
|
|
(37,346
|
)
|
|
|
|||
Balance at December 31, 2017
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Calculated using Level 3 inputs.
|
(2)
|
Financing-related accretion revisions were recorded in Interest expense in the consolidated statements of operations.
|
(3)
|
Recorded as revisions within Common units in the consolidated balance sheets and consolidated statements of equity and partners’ capital.
|
(4)
|
Accretion expense was recorded as a charge to Interest expense in the consolidated statements of operations.
|
thousands except per-unit amounts
Quarters Ended
|
|
Total Quarterly
Distribution
per Unit
|
|
Total Quarterly
Cash Distribution
|
|
Date of
Distribution
|
|||||
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
|
|
0.800
|
|
|
152,588
|
|
|
February 2016
|
|||
2016
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.815
|
|
|
$
|
158,905
|
|
|
May 2016
|
|
June 30
|
|
0.830
|
|
|
162,827
|
|
|
August 2016
|
|||
September 30
|
|
0.845
|
|
|
166,742
|
|
|
November 2016
|
|||
December 31
|
|
0.860
|
|
|
170,657
|
|
|
February 2017
|
|||
2017
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.875
|
|
|
$
|
188,753
|
|
|
May 2017
|
|
June 30
|
|
0.890
|
|
|
207,491
|
|
|
August 2017
|
|||
September 30
|
|
0.905
|
|
|
212,038
|
|
|
November 2017
|
|||
December 31
(1)
|
|
0.920
|
|
|
216,586
|
|
|
February 2018
|
(1)
|
The Board of Directors declared a cash distribution to the Partnership’s unitholders for the
fourth quarter
of
2017
of
$0.920
per unit, or
$216.6 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 13, 2018
, to unitholders of record at the close of business on
February 1, 2018
.
|
thousands except per-unit amounts
Quarters Ended
|
|
Total Quarterly
Distribution
per Unit
|
|
Total Quarterly
Cash Distribution
|
|
Date of
Distribution
|
|||||
2016
|
|
|
|
|
|
|
|||||
March 31
(1)
|
|
$
|
0.68
|
|
|
$
|
1,887
|
|
|
May 2016
|
|
June 30
(2)
|
|
0.68
|
|
|
14,082
|
|
|
August 2016
|
|||
September 30
|
|
0.68
|
|
|
14,907
|
|
|
November 2016
|
|||
December 31
|
|
0.68
|
|
|
14,908
|
|
|
February 2017
|
|||
2017
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.68
|
|
|
$
|
7,453
|
|
|
May 2017
|
(1)
|
Quarterly per unit distribution prorated for the
18
-day period during which
14,030,611
Series A Preferred units were outstanding during the first quarter of 2016.
|
(2)
|
Full quarterly per unit distribution on 14,030,611 Series A Preferred units and quarterly per unit distribution prorated for the
77
-day period during which
7,892,220
Series A Preferred units were outstanding during the second quarter of 2016.
|
|
|
Common
Units
|
|
Class C
Units
|
|
Series A
Preferred
Units
|
|
General
Partner
Units
|
|
Total
|
|||||
Balance at December 31, 2015
|
|
128,576,965
|
|
|
11,411,862
|
|
|
—
|
|
|
2,583,068
|
|
|
142,571,895
|
|
PIK Class C units
|
|
—
|
|
|
946,261
|
|
|
—
|
|
|
—
|
|
|
946,261
|
|
Springfield acquisition
|
|
2,089,602
|
|
|
—
|
|
|
14,030,611
|
|
|
—
|
|
|
16,120,213
|
|
April 2016 Series A units issuance
|
|
—
|
|
|
—
|
|
|
7,892,220
|
|
|
—
|
|
|
7,892,220
|
|
Long-Term Incentive Plan award vestings
|
|
5,403
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,403
|
|
Balance at December 31, 2016
|
|
130,671,970
|
|
|
12,358,123
|
|
|
21,922,831
|
|
|
2,583,068
|
|
|
167,535,992
|
|
PIK Class C units
|
|
—
|
|
|
885,760
|
|
|
—
|
|
|
—
|
|
|
885,760
|
|
Conversion of Series A Preferred units
|
|
21,922,831
|
|
|
—
|
|
|
(21,922,831
|
)
|
|
—
|
|
|
—
|
|
Long-Term Incentive Plan award vestings
|
|
7,304
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,304
|
|
Balance at December 31, 2017
|
|
152,602,105
|
|
|
13,243,883
|
|
|
—
|
|
|
2,583,068
|
|
|
168,429,056
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands except per-unit amounts
|
|
2017
|
|
2016
|
|
2015
|
||||||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
567,483
|
|
|
$
|
591,331
|
|
|
$
|
4,106
|
|
Pre-acquisition net (income) loss allocated to Anadarko
|
|
—
|
|
|
(11,326
|
)
|
|
(79,386
|
)
|
|||
Series A Preferred units interest in net (income) loss
(1)
|
|
(42,373
|
)
|
|
(76,893
|
)
|
|
—
|
|
|||
General partner interest in net (income) loss
|
|
(303,835
|
)
|
|
(236,561
|
)
|
|
(180,996
|
)
|
|||
Common and Class C limited partners’ interest in net income (loss)
|
|
$
|
221,275
|
|
|
$
|
266,551
|
|
|
$
|
(256,276
|
)
|
Net income (loss) allocable to common units
(1)
|
|
$
|
192,066
|
|
|
$
|
226,611
|
|
|
$
|
(250,210
|
)
|
Net income (loss) allocable to Class C units
(1)
|
|
29,209
|
|
|
39,940
|
|
|
(6,066
|
)
|
|||
Common and Class C limited partners’ interest in net income (loss)
|
|
$
|
221,275
|
|
|
$
|
266,551
|
|
|
$
|
(256,276
|
)
|
Net income (loss) per unit
|
|
|
|
|
|
|
||||||
Common units – basic and diluted
(2)
|
|
$
|
1.30
|
|
|
$
|
1.74
|
|
|
$
|
(1.95
|
)
|
Weighted-average units outstanding
|
|
|
|
|
|
|
||||||
Common units – basic and diluted
|
|
147,194
|
|
|
130,253
|
|
|
128,345
|
|
|||
Excluded due to anti-dilutive effect:
|
|
|
|
|
|
|
||||||
Class C units
(2)
|
|
12,776
|
|
|
11,945
|
|
|
11,114
|
|
|||
Series A Preferred units assuming conversion to common units
(2)
|
|
5,406
|
|
|
16,860
|
|
|
—
|
|
(1)
|
Adjusted to reflect amortization of the beneficial conversion features.
|
(2)
|
The impact of Class C units and the conversion of Series A Preferred units would be anti-dilutive for all periods presented. On March 1, 2017,
50%
of the outstanding Series A Preferred units converted into common units on a
one
-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a
one
-for-one basis.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2017
|
|
2016
|
|
2015
|
||||||
Gains (losses) on commodity price swap agreements related to sales:
(1)
|
|
|
|
|
|
|
||||||
Natural gas sales
|
|
$
|
19,924
|
|
|
$
|
11,116
|
|
|
$
|
45,978
|
|
Natural gas liquids sales
|
|
(21,722
|
)
|
|
59,918
|
|
|
145,258
|
|
|||
Total
|
|
(1,798
|
)
|
|
71,034
|
|
|
191,236
|
|
|||
Gains (losses) on commodity price swap agreements related to purchases
(2)
|
|
2,446
|
|
|
(42,577
|
)
|
|
(124,944
|
)
|
|||
Net gains (losses) on commodity price swap agreements
|
|
$
|
648
|
|
|
$
|
28,457
|
|
|
$
|
66,292
|
|
(1)
|
Reported in affiliate Natural gas and natural gas liquids sales in the consolidated statements of operations in the period in which the related sale is recorded.
|
(2)
|
Reported in Cost of product in the consolidated statements of operations in the period in which the related purchase is recorded.
|
|
|
DJ Basin Complex
|
||||||||||||||||||
per barrel except natural gas
|
|
2015 - 2018
Swap Prices
|
|
2015 Market Prices
(1)
|
|
2016 Market Prices
(1)
|
|
2017 Market Prices
(1)
|
|
2018 Market Prices
(1)
|
||||||||||
Ethane
|
|
$
|
18.41
|
|
|
$
|
1.96
|
|
|
$
|
0.60
|
|
|
$
|
5.09
|
|
|
$
|
5.41
|
|
Propane
|
|
47.08
|
|
|
13.10
|
|
|
10.98
|
|
|
18.85
|
|
|
28.72
|
|
|||||
Isobutane
|
|
62.09
|
|
|
19.75
|
|
|
17.23
|
|
|
26.83
|
|
|
32.92
|
|
|||||
Normal butane
|
|
54.62
|
|
|
18.99
|
|
|
16.86
|
|
|
26.20
|
|
|
32.71
|
|
|||||
Natural gasoline
|
|
72.88
|
|
|
52.59
|
|
|
26.15
|
|
|
41.84
|
|
|
48.04
|
|
|||||
Condensate
|
|
76.47
|
|
|
52.59
|
|
|
34.65
|
|
|
45.40
|
|
|
49.36
|
|
|||||
Natural gas (per MMBtu)
|
|
5.96
|
|
|
2.75
|
|
|
2.11
|
|
|
3.05
|
|
|
2.21
|
|
|
|
Hugoton System
(2)
|
||||||||||
per barrel except natural gas
|
|
2015 - 2016 Swap Prices
|
|
2015 Market Prices
(1)
|
|
2016 Market Prices
(1)
|
||||||
Condensate
|
|
$
|
78.61
|
|
|
$
|
32.56
|
|
|
$
|
18.81
|
|
Natural gas (per MMBtu)
|
|
5.50
|
|
|
2.74
|
|
|
2.12
|
|
|
|
MGR Assets
|
||||||||||||||
per barrel except natural gas
|
|
2015 Swap Prices
|
|
2016 - 2018 Swap Prices
|
|
2017 Market Prices
(1)
|
|
2018 Market Prices
(1)
|
||||||||
Ethane
|
|
$
|
23.41
|
|
|
$
|
23.11
|
|
|
$
|
4.08
|
|
|
$
|
2.52
|
|
Propane
|
|
52.99
|
|
|
52.90
|
|
|
19.24
|
|
|
25.83
|
|
||||
Isobutane
|
|
74.02
|
|
|
73.89
|
|
|
25.79
|
|
|
30.03
|
|
||||
Normal butane
|
|
65.04
|
|
|
64.93
|
|
|
25.16
|
|
|
29.82
|
|
||||
Natural gasoline
|
|
81.82
|
|
|
81.68
|
|
|
45.01
|
|
|
47.25
|
|
||||
Condensate
|
|
81.82
|
|
|
81.68
|
|
|
53.55
|
|
|
56.76
|
|
||||
Natural gas (per MMBtu)
|
|
4.66
|
|
|
4.87
|
|
|
3.05
|
|
|
2.21
|
|
(1)
|
Represents the New York Mercantile Exchange forward strip price as of June 25, 2015, December 8, 2015, December 1, 2016, and
December 20, 2017
, for the 2015 Market Prices, 2016 Market Prices, 2017 Market Prices, and 2018 Market Prices, respectively, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.
|
(2)
|
The Hugoton system was sold in October 2016. See
Note 2
.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2017
|
|
2016
|
|
2015
|
||||||
General and administrative expenses
|
|
$
|
31,733
|
|
|
$
|
29,360
|
|
|
$
|
22,896
|
|
Public company expenses
|
|
9,379
|
|
|
8,410
|
|
|
8,950
|
|
|||
Total reimbursement
|
|
$
|
41,112
|
|
|
$
|
37,770
|
|
|
$
|
31,846
|
|
|
|
2017
|
|
2016
|
|
2015
|
|||||||||||||||
|
|
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
|
|
$
|
49.30
|
|
|
7,304
|
|
|
$
|
68.78
|
|
|
5,477
|
|
|
$
|
60.74
|
|
|
9,522
|
|
Vested
|
|
49.30
|
|
|
(7,304
|
)
|
|
68.78
|
|
|
(5,477
|
)
|
|
60.69
|
|
|
(9,257
|
)
|
|||
Granted
|
|
55.73
|
|
|
7,180
|
|
|
49.30
|
|
|
7,304
|
|
|
69.10
|
|
|
5,212
|
|
|||
Phantom units outstanding at end of year
|
|
55.73
|
|
|
7,180
|
|
|
49.30
|
|
|
7,304
|
|
|
68.78
|
|
|
5,477
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
||||||||||||
thousands
|
|
Purchases
|
|
Sales
|
||||||||||||||||||||
Cash consideration
|
|
$
|
3,910
|
|
|
$
|
3,965
|
|
|
$
|
10,903
|
|
|
$
|
—
|
|
|
$
|
623
|
|
|
$
|
925
|
|
Net carrying value
|
|
(5,283
|
)
|
|
(3,366
|
)
|
|
(6,318
|
)
|
|
—
|
|
|
(605
|
)
|
|
(972
|
)
|
||||||
Partners’ capital adjustment
|
|
$
|
(1,373
|
)
|
|
$
|
599
|
|
|
$
|
4,585
|
|
|
$
|
—
|
|
|
$
|
18
|
|
|
$
|
(47
|
)
|
|
|
Year ended December 31,
|
||||||||||
thousands
|
|
2017
|
|
2016
|
|
2015
|
||||||
Revenues and other
(1)
|
|
$
|
1,365,318
|
|
|
$
|
1,228,232
|
|
|
$
|
1,220,639
|
|
Equity income, net
– affiliates
(1)
|
|
85,194
|
|
|
78,717
|
|
|
71,251
|
|
|||
Cost of product
(1)
|
|
86,010
|
|
|
80,455
|
|
|
167,354
|
|
|||
Operation and maintenance
(2)
|
|
72,489
|
|
|
72,330
|
|
|
77,061
|
|
|||
General and administrative
(3)
|
|
39,130
|
|
|
38,066
|
|
|
33,903
|
|
|||
Operating expenses
|
|
197,629
|
|
|
190,851
|
|
|
278,318
|
|
|||
Interest income
(4)
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
(5)
|
|
71
|
|
|
(7,747
|
)
|
|
14,398
|
|
|||
Settlement of the Deferred purchase price obligation – Anadarko
(6)
|
|
(37,346
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from the issuance of common units, net of offering expenses
(7)
|
|
—
|
|
|
25,000
|
|
|
—
|
|
|||
Distributions to unitholders
(8)
|
|
452,777
|
|
|
382,711
|
|
|
314,200
|
|
|||
Above-market component of swap agreements with Anadarko
|
|
58,551
|
|
|
45,820
|
|
|
18,449
|
|
(1)
|
Represents amounts earned or incurred on and subsequent to the date of the acquisition of 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 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 acquisition of 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)
|
Includes amounts related to the Deferred purchase price obligation - Anadarko (see
Note 2
and
Note 12
).
|
(6)
|
Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko (see
Note 2
).
|
(7)
|
Represents proceeds from the issuance of
835,841
common units to WGP as partial funding for the acquisition of Springfield (see
Note 2
).
|
(8)
|
Represents distributions paid under the partnership agreement (see
Note 3
and
Note 4
).
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2017
|
|
2016
|
|
2015
|
||||||
Current income tax expense (benefit)
|
|
|
|
|
|
|
||||||
Federal income tax expense (benefit)
|
|
$
|
—
|
|
|
$
|
4,477
|
|
|
$
|
32,422
|
|
State income tax expense (benefit)
|
|
2,408
|
|
|
1,340
|
|
|
1,764
|
|
|||
Total current income tax expense (benefit)
|
|
2,408
|
|
|
5,817
|
|
|
34,186
|
|
|||
Deferred income tax expense (benefit)
|
|
|
|
|
|
|
||||||
Federal income tax expense (benefit)
|
|
—
|
|
|
1,622
|
|
|
10,251
|
|
|||
State income tax expense (benefit)
|
|
2,458
|
|
|
933
|
|
|
1,095
|
|
|||
Total deferred income tax expense (benefit)
|
|
2,458
|
|
|
2,555
|
|
|
11,346
|
|
|||
Total income tax expense (benefit)
|
|
$
|
4,866
|
|
|
$
|
8,372
|
|
|
$
|
45,532
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands except percentages
|
|
2017
|
|
2016
|
|
2015
|
||||||
Income (loss) before income taxes
|
|
$
|
583,084
|
|
|
$
|
610,666
|
|
|
$
|
59,739
|
|
Statutory tax rate
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Tax computed at statutory rate
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Adjustments resulting from:
|
|
|
|
|
|
|
||||||
Federal taxes on income attributable to Partnership assets pre-acquisition
|
|
—
|
|
|
6,162
|
|
|
42,823
|
|
|||
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit)
|
|
—
|
|
|
117
|
|
|
298
|
|
|||
Texas margin tax expense (benefit)
(1)
|
|
4,866
|
|
|
2,093
|
|
|
2,411
|
|
|||
Income tax expense (benefit)
|
|
$
|
4,866
|
|
|
$
|
8,372
|
|
|
$
|
45,532
|
|
Effective tax rate
|
|
1
|
%
|
|
1
|
%
|
|
76
|
%
|
(1)
|
Includes a reduction of
$2.2 million
in deferred state income taxes for the year ended December 31, 2015. 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
|
|
2017
|
|
2016
|
||||
Depreciable property
|
|
$
|
(7,676
|
)
|
|
$
|
(4,976
|
)
|
Credit carryforwards
|
|
448
|
|
|
498
|
|
||
Other intangible assets
|
|
(189
|
)
|
|
(1,928
|
)
|
||
Other
|
|
8
|
|
|
4
|
|
||
Net long-term deferred income tax liabilities
|
|
$
|
(7,409
|
)
|
|
$
|
(6,402
|
)
|
|
|
|
|
December 31,
|
||||||
thousands
|
|
Estimated Useful Life
|
|
2017
|
|
2016
|
||||
Land
|
|
n/a
|
|
$
|
4,450
|
|
|
$
|
4,012
|
|
Gathering systems and processing complexes
|
|
3 to 47 years
|
|
7,114,701
|
|
|
6,462,053
|
|
||
Pipelines and equipment
|
|
15 to 45 years
|
|
137,644
|
|
|
139,646
|
|
||
Assets under construction
|
|
n/a
|
|
577,914
|
|
|
226,626
|
|
||
Other
|
|
3 to 40 years
|
|
36,393
|
|
|
29,605
|
|
||
Total property, plant and equipment
|
|
|
|
7,871,102
|
|
|
6,861,942
|
|
||
Accumulated depreciation
|
|
|
|
2,140,211
|
|
|
1,812,010
|
|
||
Net property, plant and equipment
|
|
|
|
$
|
5,730,891
|
|
|
$
|
5,049,932
|
|
|
|
December 31,
|
||||||
thousands
|
|
2017
|
|
2016
|
||||
Gross carrying amount
|
|
$
|
868,035
|
|
|
$
|
868,035
|
|
Accumulated amortization
|
|
(92,766
|
)
|
|
(64,337
|
)
|
||
Other intangible assets
|
|
$
|
775,269
|
|
|
$
|
803,698
|
|
|
|
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, 2015
|
|
$
|
17,122
|
|
|
$
|
50,439
|
|
|
$
|
50,913
|
|
|
$
|
117,089
|
|
|
$
|
16,283
|
|
|
$
|
194,803
|
|
|
$
|
172,238
|
|
|
$
|
618,887
|
|
Investment earnings (loss), net of amortization
|
|
608
|
|
|
13,858
|
|
|
1,931
|
|
|
26,204
|
|
|
708
|
|
|
16,683
|
|
|
18,725
|
|
|
78,717
|
|
||||||||
Contributions
|
|
—
|
|
|
441
|
|
|
—
|
|
|
—
|
|
|
166
|
|
|
(580
|
)
|
|
—
|
|
|
27
|
|
||||||||
Distributions
|
|
(1,543
|
)
|
|
(13,277
|
)
|
|
(3,873
|
)
|
|
(26,243
|
)
|
|
(730
|
)
|
|
(16,934
|
)
|
|
(19,585
|
)
|
|
(82,185
|
)
|
||||||||
Distributions in excess of cumulative earnings
(8)
|
|
(3,354
|
)
|
|
(4,142
|
)
|
|
(2,232
|
)
|
|
(4,245
|
)
|
|
(581
|
)
|
|
(4,778
|
)
|
|
(1,906
|
)
|
|
(21,238
|
)
|
||||||||
Balance at December 31, 2016
|
|
$
|
12,833
|
|
|
$
|
47,319
|
|
|
$
|
46,739
|
|
|
$
|
112,805
|
|
|
$
|
15,846
|
|
|
$
|
189,194
|
|
|
$
|
169,472
|
|
|
$
|
594,208
|
|
Investment earnings (loss), net of amortization
|
|
3,821
|
|
|
12,547
|
|
|
1,144
|
|
|
29,444
|
|
|
3,350
|
|
|
17,387
|
|
|
17,501
|
|
|
85,194
|
|
||||||||
Impairment expense
(9)
|
|
(3,110
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,110
|
)
|
||||||||
Contributions
|
|
—
|
|
|
277
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
107
|
|
|
—
|
|
|
384
|
|
||||||||
Distributions
|
|
(4,217
|
)
|
|
(11,965
|
)
|
|
(3,085
|
)
|
|
(29,482
|
)
|
|
(3,317
|
)
|
|
(17,639
|
)
|
|
(17,675
|
)
|
|
(87,380
|
)
|
||||||||
Distributions in excess of cumulative earnings
(8)
|
|
(2,297
|
)
|
|
(3,233
|
)
|
|
(2,270
|
)
|
|
(2,468
|
)
|
|
—
|
|
|
(10,074
|
)
|
|
(2,743
|
)
|
|
(23,085
|
)
|
||||||||
Balance at December 31, 2017
|
|
$
|
7,030
|
|
|
$
|
44,945
|
|
|
$
|
42,528
|
|
|
$
|
110,299
|
|
|
$
|
15,879
|
|
|
$
|
178,975
|
|
|
$
|
166,555
|
|
|
$
|
566,211
|
|
(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, which owns
two
NGL gathering systems that link natural gas processing plants to TEP. Midcoast Energy Partners, L.P., a wholly-owned subsidiary of Enbridge, Inc., 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 owns 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 FRP, which owns 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, are calculated on an individual investment basis.
|
(9)
|
Recorded in Impairments in the consolidated statements of operations.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2017
|
|
2016
|
|
2015
|
||||||
Consolidated Statements of Income
|
|
|
|
|
|
|
||||||
Revenues
|
|
$
|
703,424
|
|
|
$
|
687,554
|
|
|
$
|
667,554
|
|
Operating income
|
|
435,735
|
|
|
428,454
|
|
|
359,899
|
|
|||
Net income
|
|
434,749
|
|
|
427,511
|
|
|
359,443
|
|
|
|
December 31,
|
||||||
thousands
|
|
2017
|
|
2016
|
||||
Consolidated Balance Sheets
|
|
|
|
|
||||
Current assets
|
|
$
|
137,957
|
|
|
$
|
118,472
|
|
Property, plant and equipment, net
|
|
2,512,214
|
|
|
2,626,466
|
|
||
Other assets
|
|
36,373
|
|
|
39,802
|
|
||
Total assets
|
|
$
|
2,686,544
|
|
|
$
|
2,784,740
|
|
Current liabilities
|
|
80,490
|
|
|
63,468
|
|
||
Non-current liabilities
|
|
7,447
|
|
|
6,662
|
|
||
Equity
|
|
2,598,607
|
|
|
2,714,610
|
|
||
Total liabilities and equity
|
|
$
|
2,686,544
|
|
|
$
|
2,784,740
|
|
|
|
December 31,
|
||||||
thousands
|
|
2017
|
|
2016
|
||||
Trade receivables, net
|
|
$
|
160,387
|
|
|
$
|
192,808
|
|
Other receivables, net
|
|
45
|
|
|
30,415
|
|
||
Total accounts receivable, net
|
|
$
|
160,432
|
|
|
$
|
223,223
|
|
|
|
December 31,
|
||||||
thousands
|
|
2017
|
|
2016
|
||||
Natural gas liquids inventory
|
|
$
|
10,788
|
|
|
$
|
7,126
|
|
Imbalance receivables
|
|
1,640
|
|
|
3,483
|
|
||
Prepaid insurance
|
|
2,388
|
|
|
2,257
|
|
||
Total other current assets
|
|
$
|
14,816
|
|
|
$
|
12,866
|
|
|
|
December 31,
|
||||||
thousands
|
|
2017
|
|
2016
|
||||
Accrued interest expense
|
|
$
|
40,632
|
|
|
$
|
39,826
|
|
Short-term asset retirement obligations
|
|
2,304
|
|
|
3,114
|
|
||
Short-term remediation and reclamation obligations
|
|
833
|
|
|
630
|
|
||
Income taxes payable
|
|
2,495
|
|
|
1,006
|
|
||
Other
|
|
1,635
|
|
|
532
|
|
||
Total accrued liabilities
|
|
$
|
47,899
|
|
|
$
|
45,108
|
|
|
|
Year Ended December 31,
|
||||||
thousands
|
|
2017
|
|
2016
|
||||
Carrying amount of asset retirement obligations at beginning of year
|
|
$
|
142,407
|
|
|
$
|
130,631
|
|
Liabilities incurred
|
|
16,153
|
|
|
5,515
|
|
||
Liabilities settled
|
|
(10,468
|
)
|
|
(10,650
|
)
|
||
Accretion expense
|
|
6,956
|
|
|
6,794
|
|
||
Revisions in estimated liabilities
|
|
(9,350
|
)
|
|
10,117
|
|
||
Carrying amount of asset retirement obligations at end of year
|
|
$
|
145,698
|
|
|
$
|
142,407
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||||||||||
thousands
|
|
Principal
|
|
Carrying
Value
|
|
Fair
Value
(1)
|
|
Principal
|
|
Carrying
Value
|
|
Fair
Value
(1)
|
||||||||||||
2021 Notes
|
|
$
|
500,000
|
|
|
$
|
495,815
|
|
|
$
|
530,647
|
|
|
$
|
500,000
|
|
|
$
|
494,734
|
|
|
$
|
536,252
|
|
2022 Notes
|
|
670,000
|
|
|
668,849
|
|
|
684,043
|
|
|
670,000
|
|
|
668,634
|
|
|
681,723
|
|
||||||
2018 Notes
|
|
350,000
|
|
|
349,684
|
|
|
350,631
|
|
|
350,000
|
|
|
349,188
|
|
|
351,531
|
|
||||||
2044 Notes
|
|
600,000
|
|
|
593,234
|
|
|
637,827
|
|
|
600,000
|
|
|
593,132
|
|
|
615,753
|
|
||||||
2025 Notes
|
|
500,000
|
|
|
491,885
|
|
|
500,885
|
|
|
500,000
|
|
|
490,971
|
|
|
492,499
|
|
||||||
2026 Notes
|
|
500,000
|
|
|
495,245
|
|
|
520,144
|
|
|
500,000
|
|
|
494,802
|
|
|
518,441
|
|
||||||
RCF
|
|
370,000
|
|
|
370,000
|
|
|
370,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total long-term debt
|
|
$
|
3,490,000
|
|
|
$
|
3,464,712
|
|
|
$
|
3,594,177
|
|
|
$
|
3,120,000
|
|
|
$
|
3,091,461
|
|
|
$
|
3,196,199
|
|
(1)
|
Fair value is measured using the market approach and Level 2 inputs.
|
thousands
|
|
Carrying Value
|
||
Balance at December 31, 2015
|
|
$
|
2,690,651
|
|
RCF borrowings
|
|
600,000
|
|
|
Issuance of 2026 Notes
|
|
500,000
|
|
|
Issuance of 2044 Notes
|
|
200,000
|
|
|
Repayments of RCF borrowings
|
|
(900,000
|
)
|
|
Other
|
|
810
|
|
|
Balance at December 31, 2016
|
|
$
|
3,091,461
|
|
RCF borrowings
|
|
370,000
|
|
|
Other
|
|
3,251
|
|
|
Balance at December 31, 2017
|
|
$
|
3,464,712
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2017
|
|
2016
|
|
2015
|
||||||
Third parties
|
|
|
|
|
|
|
||||||
Long-term debt
|
|
$
|
(142,525
|
)
|
|
$
|
(121,832
|
)
|
|
$
|
(102,058
|
)
|
Amortization of debt issuance costs and commitment fees
|
|
(6,616
|
)
|
|
(6,398
|
)
|
|
(5,734
|
)
|
|||
Capitalized interest
|
|
6,826
|
|
|
5,562
|
|
|
8,318
|
|
|||
Total interest expense – third parties
|
|
(142,315
|
)
|
|
(122,668
|
)
|
|
(99,474
|
)
|
|||
Affiliates
|
|
|
|
|
|
|
||||||
Deferred purchase price obligation – Anadarko
(1)
|
|
(71
|
)
|
|
7,747
|
|
|
(14,398
|
)
|
|||
Total interest expense – affiliates
|
|
(71
|
)
|
|
7,747
|
|
|
(14,398
|
)
|
|||
Interest expense
|
|
$
|
(142,386
|
)
|
|
$
|
(114,921
|
)
|
|
$
|
(113,872
|
)
|
(1)
|
See
Note 2
for a discussion of the Deferred purchase price obligation - Anadarko.
|
thousands
|
|
Operating Leases
|
||
2018
|
|
$
|
8,402
|
|
2019
|
|
7,506
|
|
|
2020
|
|
1,615
|
|
|
2021
|
|
460
|
|
|
2022
|
|
467
|
|
|
Thereafter
|
|
2,021
|
|
|
Total
|
|
$
|
20,471
|
|
thousands except per-unit amounts
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
2017
|
|
|
|
|
|
|
|
|
||||||||
Total revenues and other
|
|
$
|
516,193
|
|
|
$
|
525,450
|
|
|
$
|
574,695
|
|
|
$
|
632,018
|
|
Equity income, net – affiliates
|
|
19,461
|
|
|
21,728
|
|
|
21,519
|
|
|
22,486
|
|
||||
Gain (loss) on divestiture and other, net
|
|
119,487
|
|
|
15,458
|
|
|
72
|
|
|
(2,629
|
)
|
||||
Proceeds from business interruption insurance claims
|
|
5,767
|
|
|
24,115
|
|
|
—
|
|
|
—
|
|
||||
Operating income (loss)
|
|
138,392
|
|
|
207,608
|
|
|
179,456
|
|
|
181,815
|
|
||||
Net income (loss)
|
|
103,991
|
|
|
175,497
|
|
|
147,913
|
|
|
150,817
|
|
||||
Net income (loss) attributable to Western Gas Partners, LP
|
|
101,889
|
|
|
173,451
|
|
|
143,506
|
|
|
148,637
|
|
||||
Net income (loss) per common unit – basic and diluted
(1)
|
|
0.01
|
|
|
0.49
|
|
|
0.38
|
|
|
0.39
|
|
||||
2016
|
|
|
|
|
|
|
|
|
||||||||
Total revenues and other
|
|
$
|
383,141
|
|
|
$
|
428,664
|
|
|
$
|
481,645
|
|
|
$
|
510,820
|
|
Equity income, net – affiliates
|
|
16,814
|
|
|
19,693
|
|
|
20,294
|
|
|
21,916
|
|
||||
Gain (loss) on divestiture and other, net
|
|
(632
|
)
|
|
(1,907
|
)
|
|
(6,230
|
)
|
|
(5,872
|
)
|
||||
Proceeds from business interruption insurance claims
|
|
—
|
|
|
2,603
|
|
|
13,667
|
|
|
—
|
|
||||
Operating income (loss)
|
|
153,403
|
|
|
176,362
|
|
|
197,288
|
|
|
181,155
|
|
||||
Net income (loss)
|
|
119,083
|
|
|
167,325
|
|
|
170,426
|
|
|
145,460
|
|
||||
Net income (loss) attributable to Western Gas Partners, LP
|
|
116,060
|
|
|
164,521
|
|
|
167,746
|
|
|
143,004
|
|
||||
Net income (loss) per common unit – basic and diluted
(1)
|
|
0.31
|
|
|
0.55
|
|
|
0.54
|
|
|
0.35
|
|
(1)
|
Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets.
|
Name
|
|
Age
|
|
Position with Western Gas Holdings, LLC
|
|
Robert G. Gwin
|
|
54
|
|
|
Chairman of the Board
|
Donald R. Sinclair
|
|
60
|
|
|
President, Chief Executive Officer and Director (through February 12, 2017)
|
Benjamin M. Fink
|
|
47
|
|
|
President, Chief Executive Officer and Director
|
Jaime R. Casas
|
|
47
|
|
|
Senior Vice President, Chief Financial Officer and Treasurer
|
Craig W. Collins
|
|
45
|
|
|
Senior Vice President and Chief Operating Officer
|
Philip H. Peacock
|
|
46
|
|
|
Senior Vice President, General Counsel and Corporate Secretary
|
Steven D. Arnold
|
|
57
|
|
|
Director
|
Daniel E. Brown
|
|
42
|
|
|
Director
|
Milton Carroll
|
|
67
|
|
|
Director
|
James R. Crane
|
|
64
|
|
|
Director
|
Darrell E. Hollek
|
|
60
|
|
|
Director (through December 31, 2017)
|
Robert K. Reeves
|
|
60
|
|
|
Director
|
David J. Tudor
|
|
58
|
|
|
Director
|
Robert G. Gwin
Age: 54
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 2007 and has served as Chairman of the Board of our general partner since 2009. He also served as Chief Executive Officer of our general partner from 2007 to 2010 and as President from 2007 to 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 has also served as Chairman of the Board of LyondellBasell Industries N.V. since August 2013 and as a director since 2011.
|
|
|
Donald R. Sinclair
Age: 60
Houston, Texas
Director from:
October 2009 to February 2017
Not Independent
Officer from:
October 2009 to February 2017
|
Biography/Qualifications
From 2010 until his retirement in February 2017, Mr. Sinclair served as President, Chief Executive Officer and a director of our general partner and from 2009 to 2010, he served as President and a director. From September 2012 to February 2017, Mr. Sinclair also served as the President and Chief Executive Officer and as a director of WGP GP. From May 2013 to February 2017, he served as Senior Vice President of Anadarko, 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 35 years, with a focus on marketing and trading and the midstream sector.
|
|
|
Benjamin M. Fink
Age: 47
Houston, Texas
Director since:
February 2017
Not Independent
Officer since:
2009
|
Biography/Qualifications
Benjamin M. Fink has served as President and Chief Executive Officer of our general partner and WGP GP since May 2017 and as a director since February 2017. He previously served as President, Chief Executive Officer, Chief Financial Officer and Treasurer of our general partner and WGP GP from February 2017 to May 2017, and as Senior Vice President and Chief Financial Officer of our general partner from 2009 to February 2017 and of WGP GP from September 2012 to February 2017. Mr. Fink currently serves as a Senior Vice President at Anadarko, having joined the company in 2007. 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.
|
|
|
Jaime R. Casas
Age: 47
Houston, Texas
Officer since:
May 2017
|
Biography/Qualifications
Jaime R. Casas has served as Senior Vice President, Chief Financial Officer and Treasurer of our general partner and of WGP GP since May 2017. Mr. Casas also has served as a Vice President, Finance of Anadarko since May 2017. Prior to joining the Partnership and WGP, Mr. Casas served as Senior Vice President and Chief Financial Officer of Clayton Williams Energy, Inc. from October 2016 until the company’s sale in April 2017. Previously, he served as Vice President and Chief Financial Officer of the general partner of LRR Energy, L.P., a publicly traded exploration and production master limited partnership, from 2011 to October 2015, and as Vice President and Chief Financial Officer of Laredo Energy, a privately held oil and gas company, from 2009 to 2011. Prior to joining Laredo Energy, Mr. Casas worked for over a decade in various positions and industry groups in the investment banking divisions at Donaldson, Lufkin & Jenrette and Credit Suisse. Mr. Casas began his career in 1993 as a management information consultant with Andersen Consulting.
|
|
|
Craig W. Collins
Age: 45
Houston, Texas
Officer since:
February 2017
|
Biography/Qualifications
Craig W. Collins has served as Senior Vice President and Chief Operating Officer of our general partner and WGP GP since February 2017. Mr. Collins was named Vice President – Midstream for Anadarko in February 2017, and previously served as Director, Midstream Engineering for Anadarko from July 2016 to February 2017, during which time he was responsible for the engineering and construction of midstream infrastructure for Anadarko and the Partnership. He joined the Anadarko midstream organization in November 2010, where he led commercial development activities in the Eagleford shale, and was promoted to General Manager in June 2013, with commercial responsibilities for midstream assets located in Texas, New Mexico, Kansas, Louisiana, and Pennsylvania. Since joining Anadarko in 2003, Mr. Collins has also held positions of increasing responsibility in Treasury and Corporate Development.
|
|
|
Philip H. Peacock
Age: 46
Houston, Texas
Officer since:
August 2012
|
Biography/Qualifications
Philip H. Peacock has served as Senior Vice President, General Counsel and Corporate Secretary of our general partner and WGP GP since February 2017, and served as Vice President, General Counsel and Corporate Secretary of our general partner from August 2012 until February 2017. Mr. Peacock served as Vice President, General Counsel and Corporate Secretary of WGP GP from September 2012 until February 2017. Prior to joining the Partnership, 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.
|
|
|
Darrell E. Hollek
Age: 60
Houston, Texas
Director from:
May 2015 to December 2017
Not Independent
|
Biography/Qualifications
From May 2015 until his retirement in December 2017, Darrell E. Hollek served as a director of our general partner and as a director of WGP GP from May 2015 until November 2017. Mr. Hollek served as Executive Vice President, Operations of Anadarko from August 2016 to May 2017. He served as Executive Vice President, U.S. Onshore Exploration and Production of Anadarko from April 2015 to August 2016, and served as Senior Vice President, Operations (Deepwater Americas) of Anadarko from May 2013 to April 2015. Prior to these positions, 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: 60
Houston, Texas
Director since:
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 also served as a director of Key Energy Services, Inc., a publicly traded oil field services company, from 2007 to December 2016. 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: 58
Houston, Texas
Director since:
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 since 2008, and previously served as a member of the Special Committee of the Board of Directors 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 2016, Mr. Tudor has served as Chief Executive Officer and General Manager of Associated Electric Cooperative Inc., a member-owned, member-governed wholesale power provider serving Missouri, Iowa and Oklahoma. From May 2013 to May 2016, Mr. Tudor served as President and Chief Executive Officer of Champion Energy Services, a retail electric provider. 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.
|
Named Executive Officers of Our General Partner
|
|
Time
Allocated
|
|
Anadarko Corporate Officer
|
Benjamin M. Fink
|
|
90.0%
|
|
Yes
|
Jaime R. Casas
|
|
90.0%
|
|
Yes
|
Craig W. Collins
|
|
50.0%
|
|
Yes
|
Philip H. Peacock
|
|
50.0%
|
|
Yes
|
Donald R. Sinclair
|
|
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
|
•
|
certain other Anadarko benefits that are provided on the same basis to other eligible Anadarko employees, including welfare and retirement benefits, severance benefits and change of control benefits, plus other benefits.
|
•
|
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
|
•
|
certain benefits that are also provided to all other eligible U.S.-based Anadarko employees, including medical, dental, vision, flexible spending and health savings accounts, paid time off, life insurance and disability coverage.
|
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
($)
|
|||||||
Benjamin M. Fink
|
|
2017
|
|
415,385
|
|
|
—
|
|
|
2,062,764
|
|
|
1,101,952
|
|
|
325,122
|
|
|
138,498
|
|
|
4,043,721
|
|
President and
|
|
2016
|
|
332,135
|
|
|
—
|
|
|
1,634,281
|
|
|
401,340
|
|
|
259,066
|
|
|
108,526
|
|
|
2,735,348
|
|
Chief Executive Officer
|
2015
|
|
341,135
|
|
|
—
|
|
|
672,651
|
|
|
364,951
|
|
|
266,085
|
|
|
102,170
|
|
|
1,746,992
|
|
|
Jaime R. Casas
|
|
2017
|
|
208,731
|
|
|
—
|
|
|
1,257,309
|
|
|
904,934
|
|
|
135,675
|
|
|
71,607
|
|
|
2,578,256
|
|
Senior Vice President, Chief
|
|
2016
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Financial Officer and Treasurer
|
2015
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Craig W. Collins
|
|
2017
|
|
146,827
|
|
|
—
|
|
|
1,029,025
|
|
|
279,272
|
|
|
91,209
|
|
|
49,090
|
|
|
1,595,423
|
|
Senior Vice President and
|
|
2016
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Chief Operating Officer
|
|
2015
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Philip H. Peacock
|
|
2017
|
|
150,082
|
|
|
—
|
|
|
906,771
|
|
|
218,869
|
|
|
88,894
|
|
|
50,098
|
|
|
1,414,714
|
|
Senior Vice President, General Counsel
|
|
2016
|
|
129,938
|
|
|
—
|
|
|
100,020
|
|
|
—
|
|
|
62,370
|
|
|
42,427
|
|
|
334,755
|
|
and Corporate Secretary
|
|
2015
|
|
134,935
|
|
|
—
|
|
|
85,010
|
|
|
—
|
|
|
64,769
|
|
|
40,413
|
|
|
325,127
|
|
Donald R. Sinclair
|
|
2017
|
|
40,385
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12,978
|
|
|
53,363
|
|
Former President and
|
|
2016
|
|
356,971
|
|
|
—
|
|
|
1,875,920
|
|
|
615,378
|
|
|
342,692
|
|
|
116,869
|
|
|
3,307,830
|
|
Chief Executive Officer
|
|
2015
|
|
350,481
|
|
|
—
|
|
|
828,646
|
|
|
449,573
|
|
|
336,462
|
|
|
104,969
|
|
|
2,070,131
|
|
(1)
|
The amounts in this column reflect the base salary compensation allocated to us by Anadarko for the years ended December 31,
2017
,
2016
and
2015
. Mr. Sinclair’s amount reflects base salary compensation earned and allocated through February 12, 2017. Mr. Casas’ amount reflects base salary compensation earned and allocated since joining the Partnership on May 22, 2017.
|
(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 2012 Anadarko Omnibus Incentive Compensation Plans and include unvested amounts. For a discussion of valuation assumptions for the awards under the 2012 Anadarko Omnibus Incentive Compensation Plans, see
Note 22—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,
2017
(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
2017
, 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
2017
, 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,
2017
, and allocated to us for the years ended December 31,
2016
and
2015
. Given the timing of when payments are to be made in 2018, the
2017
amounts represent payments which were earned in
2017
and are expected to be paid in early
2018
, with an assumed at-target payout, which may not be indicative of the payout our named executive officers will actually receive. The
2016
amounts represent payments which were earned in
2016
and paid in early
2017
and the
2015
amounts represent the payments which were earned in
2015
and paid in early
2016
. For an explanation of the
2017
annual incentive plan awards, read
Compensation Discussion and Analysis – Analysis of
2017
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
April 5, 2018
.
|
(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,
2017
,
2016
and
2015
. Mr. Sinclair’s amounts reflect allocated expenses through February 12, 2017. The
2017
allocated expenses are detailed in the table below:
|
Name
|
|
Retirement Plan
Expense
|
|
Savings Plan
Expense
|
||||
Benjamin M. Fink
|
|
$
|
101,047
|
|
|
$
|
37,451
|
|
Jaime R. Casas
|
|
53,119
|
|
|
18,488
|
|
||
Craig W. Collins
|
|
35,872
|
|
|
13,218
|
|
||
Philip H. Peacock
|
|
36,561
|
|
|
13,537
|
|
||
Donald R. Sinclair
|
|
9,312
|
|
|
3,666
|
|
|
|
|
|
|
|
|
|
|
|
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
(#)
|
|
|
|
|
||||||||||||||
Benjamin M. Fink
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
325,122
|
|
|
390,146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
02/13/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,365
|
|
|
68.14
|
|
|
235,198
|
|
|||||||
02/13/17
|
|
|
|
|
|
|
|
1,393
|
|
|
3,482
|
|
|
6,964
|
|
|
|
|
|
|
|
|
281,528
|
|
||||||
02/13/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,477
|
|
|
|
|
|
|
168,769
|
|
||||||||
11/14/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
57,803
|
|
|
48.05
|
|
|
866,754
|
|
|||||||
11/14/17
|
|
|
|
|
|
|
|
7,268
|
|
|
18,169
|
|
|
36,338
|
|
|
|
|
|
|
|
|
993,674
|
|
||||||
11/14/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,878
|
|
|
|
|
|
|
618,793
|
|
||||||||
Jaime R. Casas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
135,675
|
|
|
162,810
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
05/22/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,174
|
|
|
53.35
|
|
|
495,194
|
|
|||||||
05/22/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,279
|
|
|
|
|
|
|
495,035
|
|
||||||||
11/14/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27,325
|
|
|
48.05
|
|
|
409,740
|
|
|||||||
11/14/17
|
|
|
|
|
|
|
|
3,436
|
|
|
8,590
|
|
|
17,180
|
|
|
|
|
|
|
|
|
469,765
|
|
||||||
11/14/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,088
|
|
|
|
|
|
|
292,509
|
|
||||||||
Craig W. Collins
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
91,209
|
|
|
109,451
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
02/13/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,678
|
|
|
68.14
|
|
|
174,209
|
|
|||||||
02/13/17
|
|
|
|
|
|
|
|
1,032
|
|
|
2,580
|
|
|
5,160
|
|
|
|
|
|
|
|
|
208,553
|
|
||||||
02/13/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,835
|
|
|
|
|
|
|
125,003
|
|
||||||||
11/14/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,007
|
|
|
48.05
|
|
|
105,063
|
|
|||||||
11/14/17
|
|
|
|
|
|
|
|
881
|
|
|
2,203
|
|
|
4,406
|
|
|
|
|
|
|
|
|
120,455
|
|
||||||
11/14/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,406
|
|
|
|
|
|
|
500,008
|
|
||||||||
11/14/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,561
|
|
|
|
|
|
|
75,006
|
|
||||||||
Philip H. Peacock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
88,894
|
|
|
106,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
03/27/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,362
|
|
|
59.94
|
|
|
105,049
|
|
|||||||
03/27/17
|
|
|
|
|
|
|
|
688
|
|
|
1,721
|
|
|
3,442
|
|
|
|
|
|
|
|
|
120,005
|
|
||||||
03/27/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,252
|
|
|
|
|
|
|
75,015
|
|
||||||||
11/14/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,591
|
|
|
48.05
|
|
|
113,820
|
|
|||||||
11/14/17
|
|
|
|
|
|
|
|
954
|
|
|
2,386
|
|
|
4,772
|
|
|
|
|
|
|
|
|
130,490
|
|
||||||
11/14/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,406
|
|
|
|
|
|
|
500,008
|
|
||||||||
11/14/17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,691
|
|
|
|
|
|
|
81,253
|
|
(1)
|
Reflects the estimated
2017
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
2017
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
2017
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
April 5, 2018
.
|
(2)
|
Reflects the estimated future payout allocable to us under Anadarko’s performance units awarded in
2017
. 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 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. In addition to the annual grants in November 2017, Messrs. Fink, Collins and Peacock received performance unit awards earlier in the year as a result of their respective promotions. For additional discussion of Anadarko’s performance unit awards, read
Compensation Discussion and Analysis — Analysis of
2017
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
April 5, 2018
.
|
(3)
|
Reflects the allocable number of restricted stock shares and restricted stock units awarded in
2017
under the Omnibus Plan. Generally speaking, these awards vest ratably over three years, beginning with the first anniversary of the grant date. For restricted stock shares, dividends are paid at the same time as dividends are paid with respect to outstanding shares of Anadarko common stock. For restricted stock units, dividend equivalents are reinvested in shares of Anadarko common stock and paid upon the applicable vesting of the underlying award. In addition to the annual grants in November 2017, Messrs. Fink, Collins and Peacock received restricted stock unit awards with three year vesting schedules earlier in the year as a result of their respective promotions, and Mr. Casas received restricted stock unit awards with a four year vesting schedule upon his hire. Also included are the 10,406 allocated special restricted stock units awarded in 2017 under the Omnibus Plan to each of Messrs. Collins and Peacock, which will vest in four years from grant date, provided Messrs. Collins and Peacock remain employed by Anadarko until such date.
|
(4)
|
Reflects the allocable number of Anadarko stock options each named executive officer was awarded in
2017
. These awards vest ratably over three years, beginning with the first anniversary of the date of grant and have a term of seven years. In addition to the annual grants in November 2017, Messrs. Fink, Collins and Peacock received Anadarko stock options with three year vesting schedules earlier in the year as a result of their respective promotions, and Mr. Casas received options with a four year vesting schedule upon his hire.
|
(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
2017
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 22—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,
2017
(which is not, and shall not be deemed to be, incorporated by reference herein).
|
Craig W. Collins
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
03/04/11
|
|
198
|
|
|
—
|
|
|
81.02
|
|
|
03/04/18
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
03/09/15
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
413
|
|
|
22,153
|
|
|
—
|
|
|
—
|
|
04/12/16
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,497
|
|
|
80,299
|
|
|
—
|
|
|
—
|
|
02/13/17
|
|
—
|
|
|
7,678
|
|
|
68.14
|
|
|
02/13/24
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
02/13/17
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,842
|
|
|
98,805
|
|
|
—
|
|
|
—
|
|
02/13/17
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,580
|
|
|
55,356
|
|
11/14/17
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,416
|
|
|
558,714
|
|
|
—
|
|
|
—
|
|
11/14/17
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,562
|
|
|
83,786
|
|
|
—
|
|
|
—
|
|
11/14/17
|
|
—
|
|
|
7,007
|
|
|
48.05
|
|
|
11/14/24
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
11/14/17
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,203
|
|
|
118,169
|
|
Philip H. Peacock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
03/09/15
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
351
|
|
|
18,828
|
|
|
—
|
|
|
—
|
|
04/12/16
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,331
|
|
|
71,395
|
|
|
—
|
|
|
—
|
|
03/27/17
|
|
—
|
|
|
5,362
|
|
|
59.94
|
|
|
03/27/24
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
03/27/17
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,721
|
|
|
92,314
|
|
03/27/17
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,256
|
|
|
67,372
|
|
|
—
|
|
|
—
|
|
11/14/17
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,416
|
|
|
558,714
|
|
|
—
|
|
|
—
|
|
11/14/17
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,693
|
|
|
90,813
|
|
|
—
|
|
|
—
|
|
11/14/17
|
|
—
|
|
|
7,591
|
|
|
48.05
|
|
|
11/14/24
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
11/14/17
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,386
|
|
|
127,985
|
|
(1)
|
Stock options have a seven-year term and will vest ratably over three years in equal installments on the first, second, and third anniversaries of the date of grant. Stock option awards do not accrue dividends or dividend equivalents.
|
(2)
|
Generally speaking, the restricted stock units and shares will vest pro-rata annually over three years, beginning with the first anniversary of the grant date. At the end of each vesting period, unless deferred, the number of restricted stock units that vest are settled in shares of unrestricted common stock, less applicable withholding taxes. For restricted stock shares, dividends are paid at the same time as dividends are paid with respect to outstanding shares of Anadarko common stock. For restricted stock units, dividend equivalents are accrued and reinvested in additional shares of common stock, less applicable withholding taxes. The 14,547 allocated special restricted stock units received in November 2016 by Mr. Fink, and the 10,406 allocated special restricted stock units received in November 2017 by each of Messrs. Collins and Peacock, as well as the corresponding dividend unit equivalents, will vest in four years from the grant date, provided Messrs. Fink, Collins and Peacock remain employed by Anadarko until such dates.
|
(3)
|
The number of outstanding units and the estimated payout percentages disclosed for each award are calculated based on Anadarko’s relative performance ranking as of December 31,
2017
, and are not necessarily indicative of what the payout percent earned will be at the end of each three-year performance period. Anadarko’s relative performance rankings as of December 31,
2017
were: 0% for the 2014 grant, 40% for the 2015 grant, 40% for the 2016 grant and 40% for the February and March 2017 grant. For awards granted in November 2017 with a performance period beginning in 2018, target payout has been assumed.
|
|
|
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)
|
||||
Benjamin M. Fink
|
|
—
|
|
|
—
|
|
|
3,691
|
|
|
184,969
|
|
Jaime R. Casas
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Craig W. Collins
|
|
—
|
|
|
—
|
|
|
1,539
|
|
|
96,238
|
|
Philip H. Peacock
|
|
—
|
|
|
—
|
|
|
1,353
|
|
|
84,646
|
|
(1)
|
Shares acquired and values realized on exercise include options exercised in
2017
. 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
2017
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.
|
|
|
Mr. Fink
|
|
Mr. Casas
|
|
Mr. Collins
|
|
Mr. Peacock
|
||||||||
Cash Severance
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
Mr. Fink
|
|
Mr. Casas
|
|
Mr. Collins
|
|
Mr. Peacock
|
||||||||
Payout of Performance Unit Awards
(1)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Continued Vesting of Restricted Stock Unit Awards
(2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Total
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Under the terms of the 2015 performance unit agreement, retirement-eligible participants, as defined by the Anadarko Petroleum Corporation Retiree Health Benefits Plan, 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. Additionally, the performance unit agreements for awards granted on or after November 10, 2016 provide for payout at the end of the performance period, with no proration and based on actual performance, in cases of a qualified retirement, or retirement at or after age 60 with minimum 10 years of service. As of December 31,
2017
, none of our named executive officers were eligible for retirement nor qualified retirement.
|
(2)
|
Under the terms of the restricted stock unit agreements effective on or after November 10, 2016, in the event of a qualified retirement, or retirement at or after age 60 with minimum 10 years of service, restricted stock units that are held for at least 180 days after grant date will be settled according to the vesting schedule. As of December 31,
2017
, none of our named executive officers were eligible for qualified retirement.
|
|
|
Mr. Fink
|
|
Mr. Casas
|
|
Mr. Collins
|
|
Mr. Peacock
|
||||||||
Cash Severance
(1)
|
|
$
|
1,252,215
|
|
|
$
|
918,225
|
|
|
$
|
452,157
|
|
|
$
|
421,249
|
|
Pro-rata Bonus
(2)
|
|
325,122
|
|
|
135,675
|
|
|
91,209
|
|
|
88,894
|
|
||||
Accelerated Anadarko Equity Awards
(3)
|
|
1,808,517
|
|
|
660,435
|
|
|
854,495
|
|
|
795,669
|
|
||||
Supplemental Pension Benefits
(4)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Medical and Dental
(5)
|
|
7,497
|
|
|
14,298
|
|
|
4,165
|
|
|
4,165
|
|
||||
Total
|
|
$
|
3,393,351
|
|
|
$
|
1,728,633
|
|
|
$
|
1,402,026
|
|
|
$
|
1,309,977
|
|
(1)
|
The values assume two times base salary plus one times target bonus multiplied by the applicable named executive officer’s allocation percentages in effect as of December 31,
2017
.
|
(2)
|
Payment, if provided, will be paid at the end of the performance period based on actual performance. The values reflect the allocated portion of our named executive officer’s assumed at-target bonus awarded under the annual incentive plan. For additional discussion of this program, read
Compensation Discussion and Analysis — Analysis of
2017
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
April 5, 2018
.
|
(3)
|
Reflects the in-the-money value of unvested stock options (subject to Anadarko’s Board of Directors approval), 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,
2017
. 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. However, the performance unit awards and the restricted stock unit awards granted on November 14, 2017, are not included in the table above as accelerated vesting upon an involuntary not for cause termination only applies to such awards if they have been held for at least 180 days after the grant date, which would not be the case in the event of such a termination that occurred on December 31, 2017. The values for Messrs. Collins and Peacock include the 10,406 allocated special restricted stock units granted on November 14, 2017, and their respective dividend equivalent units, since these grants are not subject to the 180-day hold requirement. Further, while the terms of the outstanding stock options do not require Anadarko to accelerate the vesting of the stock options upon an involuntary termination not for cause, Anadarko’s Board of Directors has a historic practice of doing so and, as such, the value of acceleration of the outstanding stock option awards is included above. The equity awards granted on and after November 10, 2016 contain a non-disclosure covenant (indefinite duration) and non-disparagement and employee non-solicitation covenants (one year). All values reflect each named executive officer’s allocation percentage as of December 31,
2017
.
|
(4)
|
Reflects the lump-sum present value of additional benefits related to Anadarko’s supplemental pension benefits which are contingent upon the termination event. The value includes special pension credits, provided through an employment agreement, retention agreement, the APC Retirement Restoration Plan or the KMG Restoration Plan, as applicable. 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, 2017, the expense would be as follows: Mr. Collins—$205,932.
|
(5)
|
Values represent six months of medical and dental active employee rate benefit coverage. These amounts are present values determined in accordance with GAAP. These values reflect their allocation percentages in effect as of December 31,
2017
.
|
|
|
Mr. Fink
|
|
Mr. Casas
|
|
Mr. Collins
|
|
Mr. Peacock
|
||||||||
Cash Severance
(1)
|
|
$
|
1,593,000
|
|
|
$
|
964,350
|
|
|
$
|
512,000
|
|
|
$
|
499,636
|
|
Pro-rata Bonus
(2)
|
|
346,500
|
|
|
135,675
|
|
|
83,500
|
|
|
87,318
|
|
||||
Accelerated Anadarko Equity Awards
(3)
|
|
3,474,522
|
|
|
1,448,031
|
|
|
1,056,450
|
|
|
1,014,466
|
|
||||
Supplemental Pension Benefits
(4)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Nonqualified Deferred Compensation
(5)
|
|
159,300
|
|
|
69,300
|
|
|
30,720
|
|
|
49,964
|
|
||||
Health and Welfare Benefits
(6)
|
|
44,265
|
|
|
68,400
|
|
|
22,162
|
|
|
21,849
|
|
||||
Total
|
|
$
|
5,617,587
|
|
|
$
|
2,685,756
|
|
|
$
|
1,704,832
|
|
|
$
|
1,673,233
|
|
(1)
|
Values assume two times the sum of base salary plus the highest bonus paid in the past three years, and reflect the allocation percentages in effect as of December 31,
2017
, per the terms of the key employee change of control agreement with Anadarko. Because Mr. Casas did not work the full year in 2017, his value was calculated using an assumed at-target allocated payout in 2017.
|
(2)
|
Values assume the full-year equivalent of the applicable named executive officer’s highest annual bonus allocated to us over the past three years. The value for Mr. Casas’ highest annual bonus was based on an estimated at-target allocated payout in 2017 as he did not receive bonus payouts in the last three years.
|
(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,
2017
. 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. The equity awards granted on and after November 10, 2016, contain a non-disclosure covenant (indefinite duration) and non-disparagement and employee non-solicitation covenants (one year). All values reflect each named executive officer’s allocation percentage as of December 31,
2017
.
|
(4)
|
Under the terms of the change of control agreement, our named executive officers 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 the applicable named executive officer was 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 the allocation percentages in effect as of December 31,
2017
, the expense would be as follows: Mr. Fink—$110,181, Mr. Casas—$71,406, Mr. Collins—$255,189, and Mr. Peacock—$31,850.
|
(5)
|
The values reflect an additional two years 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,
2017
, per the terms of their key employee change of control agreements with Anadarko.
|
(6)
|
The values represent 24 months of health and welfare benefit coverage. These amounts are present values determined in accordance with GAAP and reflect the allocation percentages as of December 31,
2017
.
|
|
|
Mr. Fink
|
|
Mr. Casas
|
|
Mr. Collins
|
|
Mr. Peacock
|
||||||||
Cash Severance
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accelerated Anadarko Equity Awards
(1)
|
|
3,474,522
|
|
|
1,448,031
|
|
|
1,056,450
|
|
|
1,014,466
|
|
||||
Health and Welfare Benefits
(2)
|
|
210,290
|
|
|
161,535
|
|
|
83,006
|
|
|
77,115
|
|
||||
Total
|
|
$
|
3,684,812
|
|
|
$
|
1,609,566
|
|
|
$
|
1,139,456
|
|
|
$
|
1,091,581
|
|
(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,
2017
. 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. The equity awards granted on and after November 10, 2016, contain a non-disclosure covenant (indefinite duration) and non-disparagement and employee non-solicitation covenants (one year). All values reflect each named executive officer’s allocation percentage as of December 31,
2017
.
|
(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 as of December 31,
2017
.
|
|
|
Mr. Fink
|
|
Mr. Casas
|
|
Mr. Collins
|
|
Mr. Peacock
|
||||||||
Cash Severance
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accelerated Anadarko Equity Awards
(1)
|
|
3,979,972
|
|
|
1,448,031
|
|
|
1,139,485
|
|
|
1,069,854
|
|
||||
Life Insurance Proceeds
(2)
|
|
1,483,924
|
|
|
1,142,622
|
|
|
568,838
|
|
|
535,862
|
|
||||
Total
|
|
$
|
5,463,896
|
|
|
$
|
2,590,653
|
|
|
$
|
1,708,323
|
|
|
$
|
1,605,716
|
|
(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,
2017
. All values reflect each named executive officer’s allocation percentage as of December 31,
2017
.
|
(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 as of December 31,
2017
, 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 annual retainer was increased to $110,000 for each board member;
|
•
|
the per-meeting fee of $2,000 for each board and committee meeting attended will be paid only to the extent a board member attends in excess of 10 total board and committee meetings in one calendar year; and
|
•
|
the value of the annual grant of phantom units was increased to approximately $100,000 on the date of grant. The non-employee directors received such a grant of phantom units on May 31, 2017.
|
Name
|
|
Fees Earned or Paid in Cash
|
|
Stock Awards
(1)
|
|
Option Awards
|
|
Non-Equity Incentive Plan Compensation
|
|
All Other Compensation
|
|
Total
|
||||||||||||
Steven D. Arnold
|
|
$
|
116,000
|
|
|
$
|
100,035
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
216,035
|
|
Milton Carroll
|
|
130,000
|
|
|
100,035
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
230,035
|
|
||||||
James R. Crane
|
|
116,000
|
|
|
100,035
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
216,035
|
|
||||||
David J. Tudor
|
|
130,000
|
|
|
100,035
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
230,035
|
|
(1)
|
The amounts included in the Stock Awards column represent the grant date fair value of non-option awards made to directors in
2017
, 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,
2017
, each of the non-employee directors had
1,795
outstanding phantom units.
|
Name
|
|
Grant Date
|
|
Phantom Units (#)
|
|
Grant Date Fair Value of Stock and Option Awards ($)
(1)
|
||
Steven D. Arnold
|
|
May 31
|
|
1,795
|
|
|
100,035
|
|
Milton Carroll
|
|
May 31
|
|
1,795
|
|
|
100,035
|
|
James R. Crane
|
|
May 31
|
|
1,795
|
|
|
100,035
|
|
David J. Tudor
|
|
May 31
|
|
1,795
|
|
|
100,035
|
|
(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
2017
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;
|
•
|
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)
|
|
52,143,426
|
|
|
34.17%
|
|
178,587,365
|
|
|
81.57%
|
Robert G. Gwin
|
|
5,000
|
|
|
*
|
|
100,000
|
|
|
*
|
Benjamin M. Fink
|
|
2,213
|
|
|
*
|
|
18,683
|
|
|
*
|
Jaime R. Casas
|
|
—
|
|
|
*
|
|
—
|
|
|
*
|
Craig W. Collins
|
|
480
|
|
|
*
|
|
400
|
|
|
*
|
Philip H. Peacock
|
|
—
|
|
|
*
|
|
7,500
|
|
|
*
|
Steven D. Arnold
(3)
|
|
36,143
|
|
|
*
|
|
7,500
|
|
|
*
|
Daniel E. Brown
|
|
—
|
|
|
*
|
|
—
|
|
|
*
|
Milton Carroll
(3) (4)
|
|
8,548
|
|
|
*
|
|
—
|
|
|
*
|
James R. Crane
(3)
|
|
11,326
|
|
|
*
|
|
—
|
|
|
*
|
Robert K. Reeves
|
|
9,000
|
|
|
*
|
|
9,000
|
|
|
*
|
David J. Tudor
(3)
|
|
10,724
|
|
|
*
|
|
7,310
|
|
|
*
|
All directors and executive officers
as a group (11 persons)
|
|
83,434
|
|
|
*
|
|
150,393
|
|
|
*
|
*
|
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
50,132,046
common units and other subsidiaries of Anadarko, AMM and AMH, collectively held
2,011,380
common units. Anadarko is the ultimate parent company of 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
13,243,883
Class C units of the Partnership.
|
(3)
|
Does not include
1,795
unvested phantom units that were granted to each of Messrs. Arnold, Carroll, Crane, and Tudor under the WES LTIP. Phantom units granted to the independent directors of WES vest 100% on the first anniversary of the date of the grant. Each vested phantom unit entitles the holder to receive a common unit or, in the discretion of our 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 units of the Partnership held in a margin account by Mr. Carroll.
|
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)
|
|
62,394
|
|
|
278,578
|
|
|
340,972
|
|
|
*
|
Benjamin M. Fink
(3)
|
|
12,513
|
|
|
52,528
|
|
|
65,041
|
|
|
*
|
Jaime R. Casas
(3)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
*
|
Craig W. Collins
(3) (4)
|
|
10,113
|
|
|
5,514
|
|
|
15,627
|
|
|
*
|
Philip H. Peacock
(3)
(4)
|
|
3,930
|
|
|
3,575
|
|
|
7,505
|
|
|
*
|
Steven D. Arnold
|
|
4,900
|
|
|
—
|
|
|
4,900
|
|
|
*
|
Daniel E. Brown
(3)
|
|
17,966
|
|
|
80,672
|
|
|
98,638
|
|
|
*
|
Milton Carroll
|
|
2,000
|
|
|
—
|
|
|
2,000
|
|
|
*
|
James R. Crane
|
|
—
|
|
|
—
|
|
|
—
|
|
|
*
|
Robert K. Reeves
(3)
|
|
220,510
|
|
|
217,880
|
|
|
438,390
|
|
|
*
|
David J. Tudor
|
|
—
|
|
|
—
|
|
|
—
|
|
|
*
|
All directors and executive officers
as a group (11 persons)
(3)
|
|
334,326
|
|
|
638,747
|
|
|
973,073
|
|
|
*
|
*
|
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 December 31,
2017
, there were 541.1 million shares of Anadarko common stock outstanding.
|
(3)
|
Does not include unvested restricted stock units of Anadarko held by the following individuals in the amounts indicated: Robert G. Gwin—40,516; Benjamin M. Fink—37,980; Jaime R. Casas—17,074; Craig W. Collins—27,603; Philip H. Peacock—26,697; Daniel E. Brown—47,565; and Robert K. Reeves—33,050; for a total of 230,485 unvested restricted stock units 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 3,820 and 3,363 unvested shares of restricted common stock of Anadarko held by Craig W. Collins and Philip H. Peacock, respectively. 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
|
|
ALPS Advisors, Inc.
1290 Broadway, Suite 1100
Denver, CO 80203
|
|
8,329,599
(1)
|
|
5.46%
|
Common Units
|
|
Tortoise Capital Advisors, L.L.C.
11550 Ash Street
Suite 300
Leawood, KS 66211
|
|
13,823,458
(2)
|
|
9.10%
|
Common Units
|
|
Kayne Anderson Capital Advisors, L.P.
1800 Avenue of the Stars Third Floor Los Angeles, CA 90067 |
|
8,974,770
(3)
|
|
5.88%
|
(1)
|
Based upon its Schedule 13G filed February 6,
2018
, with the SEC with respect to Partnership securities held as of December 31,
2017
, ALPS Advisors, Inc. (“ALPS”) has shared voting and dispositive power as to 8,329,599 common units and Alerian MLP ETF, a fund controlled by ALPS, also has shared voting and dispositive power as to 8,301,343 of the common units held by ALPS.
|
(2)
|
Based upon its Schedule 13G/A filed February 13,
2018
, with the SEC with respect to WES securities held as of December 31,
2017
, Tortoise Capital Advisors, L.L.C has shared voting power as to 11,857,986 common units and shared dispositive power as to 13,511,242 common units
|
(3)
|
Based upon its Schedule 13G/A filed February 6,
2018
, with the SEC with respect to Partnership securities held as of December 31,
2017
, Kayne Anderson Capital Advisors, L.P. has shared voting and dispositive power as to 8,974,770 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
|
|
7,180
|
|
|
—
(1)
|
|
|
2,250,000
|
|
Total
|
|
7,180
|
|
|
—
|
|
|
2,250,000
|
|
(1)
|
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 to our unitholders pro rata, including WGP and other subsidiaries of Anadarko as the holders of 50,132,046 common units and 2,011,380 common units, respectively, and to our general partner as the holder of 2,583,068 general partner units. 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 50.0% of the distributions above the highest target distribution level. As of December 31, 2017, the general partner was entitled to a maximum distribution sharing percentage of 49.5%, which includes distributions paid on its 1.5% 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 12, 2018,
we have issued 2,330,030 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
2017
); 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, 2017 |
||
Reimbursement of general and administrative expenses
|
|
$
|
31,733
|
|
Reimbursement of public company expenses
|
|
9,379
|
|
|
Total reimbursement
|
|
$
|
41,112
|
|
•
|
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,
|
||||||||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
||||||||||||
thousands
|
|
Purchases
|
|
Sales
|
||||||||||||||||||||
Cash consideration
|
|
$
|
3,910
|
|
|
$
|
3,965
|
|
|
$
|
10,903
|
|
|
$
|
—
|
|
|
$
|
623
|
|
|
$
|
925
|
|
Net carrying value
|
|
(5,283
|
)
|
|
(3,366
|
)
|
|
(6,318
|
)
|
|
—
|
|
|
(605
|
)
|
|
(972
|
)
|
||||||
Partners’ capital adjustment
|
|
$
|
(1,373
|
)
|
|
$
|
599
|
|
|
$
|
4,585
|
|
|
$
|
—
|
|
|
$
|
18
|
|
|
$
|
(47
|
)
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2017
|
|
2016
|
|
2015
|
||||||
Revenues and other
(1)
|
|
$
|
1,365,318
|
|
|
$
|
1,228,232
|
|
|
$
|
1,220,639
|
|
Equity income, net – affiliates
(1)
|
|
85,194
|
|
|
78,717
|
|
|
71,251
|
|
|||
Cost of product
(1)
|
|
86,010
|
|
|
80,455
|
|
|
167,354
|
|
|||
Operation and maintenance
(2)
|
|
72,489
|
|
|
72,330
|
|
|
77,061
|
|
|||
General and administrative
(3)
|
|
39,130
|
|
|
38,066
|
|
|
33,903
|
|
|||
Operating expenses
|
|
197,629
|
|
|
190,851
|
|
|
278,318
|
|
|||
Interest income
(4)
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
(5)
|
|
71
|
|
|
(7,747
|
)
|
|
14,398
|
|
|||
Settlement of the Deferred purchase price obligation – Anadarko
(6)
|
|
(37,346
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from the issuance of common units, net of offering expenses
(7)
|
|
—
|
|
|
25,000
|
|
|
—
|
|
|||
Distributions to unitholders
(8)
|
|
452,777
|
|
|
382,711
|
|
|
314,200
|
|
|||
Above-market component of swap agreements with Anadarko
(9)
|
|
58,551
|
|
|
45,820
|
|
|
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 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 and amounts charged by Anadarko under the omnibus agreement. 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)
|
Includes amounts related to the Deferred purchase price obligation - Anadarko. 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 the cash payment to Anadarko for the settlement of 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.
|
(7)
|
Represents proceeds from the issuance of 835,841 common units to WGP as partial funding for the acquisition of Springfield. See
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K
.
|
(8)
|
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.
|
(9)
|
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
|
|
2017
|
|
2016
|
||||
Audit fees
|
|
$
|
1,141
|
|
|
$
|
1,020
|
|
Audit-related fees
|
|
380
|
|
|
690
|
|
||
Total
|
|
$
|
1,521
|
|
|
$
|
1,710
|
|
Exhibit
Number
|
|
Description
|
2.1#
|
|
|
2.2#
|
|
|
2.3#
|
|
|
2.4#
|
|
|
2.5#
|
|
|
2.6#
|
|
|
2.7#
|
|
|
2.8#
|
|
Exhibit
Number
|
|
Description
|
2.9#
|
|
|
2.10#
|
|
|
2.11#
|
|
|
2.12#
|
|
|
2.13#
|
|
|
2.14#
|
|
|
3.1
|
|
|
3.2
|
|
|
3.3
|
|
|
3.4
|
|
|
3.5
|
|
|
3.6
|
|
|
3.7
|
|
|
4.1
|
|
|
4.2
|
|
|
4.3
|
|
Exhibit
Number
|
|
Description
|
4.4
|
|
|
4.5
|
|
|
4.6
|
|
|
4.7
|
|
|
4.8
|
|
|
4.9
|
|
|
4.10
|
|
|
4.11
|
|
|
4.12
|
|
|
4.13
|
|
|
4.14
|
|
|
4.15
|
|
|
4.16
|
|
|
10.1
|
|
|
10.2
|
|
|
10.3
|
|
|
10.4
|
|
|
10.5
|
|
Exhibit
Number
|
|
Description
|
10.6
|
|
|
10.7
|
|
|
10.8
|
|
|
10.9
|
|
|
10.10
|
|
|
10.11
|
|
|
10.12‡
|
|
|
10.13‡
|
|
|
10.14‡
|
|
|
10.15‡
|
|
|
10.16‡
|
|
|
10.17†
|
|
|
10.18
|
|
|
10.19
|
|
|
10.20
|
|
|
10.21*
|
|
|
10.22
|
|
|
10.23*
|
|
Exhibit
Number
|
|
Description
|
10.24
|
|
|
10.25
|
|
|
10.26
|
|
|
10.27†
|
|
|
10.28†
|
|
|
10.29†*
|
|
|
10.30
|
|
|
12.1*
|
|
|
21.1*
|
|
|
23.1*
|
|
|
31.1*
|
|
|
31.2*
|
|
|
32.1**
|
|
|
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 16, 2018
|
|
|
|
|
/s/ Jaime R. Casas
|
|
Jaime R. Casas
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/ Benjamin M. Fink
|
President, Chief Executive Officer and Director
|
Benjamin M. Fink
|
(Principal Executive Officer)
|
|
|
/s/ Jaime R. Casas
|
Senior Vice President, Chief Financial Officer and Treasurer
|
Jaime R. Casas
|
(Principal Financial and Accounting Officer)
|
|
|
/s/ Daniel E. Brown
|
Director
|
Daniel E. Brown
|
|
|
|
/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
|
|
|
|
|
|
|
Page
|
|
|
|
|
|
|
ARTICLE I DEFINITIONS AND ACCOUNTING TERMS
|
|
1
|
|||
|
Section 1.01
|
|
Defined Terms
|
1
|
|
|
Section 1.02
|
|
Use of Defined Terms
|
20
|
|
|
Section 1.03
|
|
Accounting Terms
|
20
|
|
|
Section 1.04
|
|
Interpretation
|
20
|
|
|
Section 1.05
|
|
Rates
|
20
|
|
|
|
|
|
|
|
ARTICLE II AMOUNT AND TERMS OF LOANS
|
20
|
||||
|
Section 2.01
|
|
Loans
|
20
|
|
|
Section 2.02
|
|
Repayment of Loans; Evidence of Debt
|
21
|
|
|
Section 2.03
|
|
Procedure for Borrowing
|
22
|
|
|
Section 2.04
|
|
Facility Fees and LC Fees
|
22
|
|
|
Section 2.05
|
|
Letters of Credit
|
23
|
|
|
Section 2.06
|
|
Reduction or Termination of Commitments
|
28
|
|
|
Section 2.07
|
|
Optional Prepayments
|
29
|
|
|
Section 2.08
|
|
Mandatory Prepayments
|
29
|
|
|
Section 2.09
|
|
Commitment Increases
|
29
|
|
|
Section 2.10
|
|
Interest
|
31
|
|
|
Section 2.11
|
|
Computation of Interest and Fees
|
32
|
|
|
Section 2.12
|
|
Funding of Borrowings
|
33
|
|
|
Section 2.13
|
|
Pro Rata Treatment and Payments
|
34
|
|
|
Section 2.14
|
|
Increased Cost of Loans
|
35
|
|
|
Section 2.15
|
|
Illegality
|
37
|
|
|
Section 2.16
|
|
Taxes
|
38
|
|
|
Section 2.17
|
|
Substitute Loan Basis
|
42
|
|
|
Section 2.18
|
|
Certain Prepayments or Continuations
|
42
|
|
|
Section 2.19
|
|
Certain Notices
|
42
|
|
|
Section 2.20
|
|
Minimum Amounts of Eurodollar Borrowings
|
43
|
|
|
Section 2.21
|
|
Break Funding Payments
|
43
|
|
|
Section 2.22
|
|
Swingline Loans
|
43
|
|
|
Section 2.23
|
|
Defaulting Lenders
|
45
|
|
|
Section 2.24
|
|
Extension of Maturity
|
47
|
|
|
Section 2.25
|
|
Alternate Rate of Interest
|
48
|
|
|
|
|
|
|
|
ARTICLE III REPRESENTATIONS AND WARRANTIES
|
|
49
|
|||
|
Section 3.01
|
|
Representations of the Borrower
|
49
|
|
|
|
|
|
|
|
ARTICLE IV AFFIRMATIVE COVENANTS
|
|
51
|
|||
|
Section 4.01
|
|
Financial Statements and Other Information
|
51
|
|
Section 4.02
|
|
Notices of Material Events
|
52
|
|
|
Section 4.03
|
|
Compliance with Laws
|
53
|
|
|
Section 4.04
|
|
Use of Proceeds
|
|
53
|
|
Section 4.05
|
|
Maintenance of Property; Insurance
|
|
53
|
|
Section 4.06
|
|
Books and Records; Inspections
|
|
53
|
|
Section 4.07
|
|
Payment of Obligations
|
|
54
|
|
Section 4.08
|
|
Material Contracts
|
|
54
|
|
Section 4.09
|
|
EEA Financial Institution
|
|
54
|
|
|
|
|
|
|
|
ARTICLE V FINANCIAL COVENANT
|
|
55
|
||
|
Section 5.01
|
|
Consolidated Leverage Ratio
|
|
55
|
|
|
|
|
|
|
|
ARTICLE VI NEGATIVE COVENANTS
|
|
55
|
||
|
Section 6.01
|
|
Nature of Business
|
|
55
|
|
Section 6.02
|
|
Liens
|
|
55
|
|
Section 6.03
|
|
Transactions with Affiliates
|
|
57
|
|
Section 6.04
|
|
Indebtedness
|
|
58
|
|
Section 6.05
|
|
Restricted Payments
|
|
58
|
|
Section 6.06
|
|
[Reserved]
|
|
58
|
|
Section 6.07
|
|
Limitations on Sales and Leasebacks
|
|
58
|
|
Section 6.08
|
|
Fundamental Changes
|
|
59
|
|
|
|
|
|
|
|
ARTICLE VII CONDITIONS OF LENDING
|
|
59
|
||
|
Section 7.01
|
|
Conditions Precedent to Effectiveness
|
|
59
|
|
Section 7.02
|
|
Conditions Precedent to Loans
|
|
61
|
|
|
|
|
|
|
|
ARTICLE VIII EVENTS OF DEFAULT
|
|
61
|
||
|
Section 8.01
|
|
Events of Default
|
|
61
|
|
|
|
|
|
|
|
ARTICLE IX THE AGENTS
|
|
|
||
|
Section 9.01
|
|
Appointment and Authority
|
|
63
|
|
Section 9.02
|
|
Exculpatory Provisions
|
|
63
|
|
Section 9.03
|
|
Reliance by Administrative Agent
|
|
64
|
|
Section 9.04
|
|
Delegation of Duties
|
|
65
|
|
Section 9.05
|
|
Right to Indemnity
|
|
65
|
|
Section 9.06
|
|
Rights as a Lender
|
|
65
|
|
Section 9.07
|
|
Non-Reliance on Administrative Agent and Other Lenders
|
66
|
|
|
Section 9.08
|
|
Events of Default
|
|
66
|
|
Section 9.09
|
|
Resignation of Administrative Agent
|
|
66
|
|
Section 9.10
|
|
No Other Duties, Etc.
|
|
67
|
|
Section 9.11
|
|
Administrative Agent May File Proofs of Claim
|
|
67
|
|
|
|
|
|
|
|
ARTICLE X MISCELLANEOUS
|
|
68
|
||
|
Section 10.01
|
|
Notices
|
|
68
|
|
Section 10.02
|
|
Waivers; Amendments
|
|
69
|
|
Section 10.03
|
|
Expenses; Indemnity; Damage Waiver
|
|
71
|
|
Section 10.04
|
|
Successors and Assigns
|
|
72
|
|
Section 10.05
|
|
Survival
|
|
77
|
|
Section 10.06
|
|
Counterparts; Integration; Effectiveness
|
|
77
|
|
Section 10.07
|
|
Severability
|
|
77
|
|
Section 10.08
|
|
Right of Setoff
|
|
77
|
|
Section 10.09
|
|
Governing Law; Jurisdiction; Consent to Service of Process
|
78
|
|
|
Section 10.10
|
|
WAIVER OF JURY TRIAL
|
|
79
|
|
Section 10.11
|
|
Headings
|
|
79
|
|
Section 10.12
|
|
Confidentiality
|
|
79
|
|
Section 10.13
|
|
Replacement of Lenders
|
|
80
|
|
Section 10.14
|
|
USA Patriot Act Notice
|
|
81
|
|
Section 10.15
|
|
No Advisory or Fiduciary Responsibility
|
|
81
|
|
Section 10.16
|
|
Amendment and Restatement
|
|
82
|
|
Section 10.17
|
|
Acknowledgment and Consent to Bail-In of EEA Financial Institution
|
82
|
Annex I
|
(List of Commitments)
|
Annex II
|
(Maximum LC Issuance Amounts)
|
|
|
Schedule I
|
(Pricing Schedule)
|
Schedule II
|
(Affiliate Agreements)
|
Schedule III
|
(Existing Letters of Credit)
|
|
|
Exhibit A
|
(Form of Note)
|
Exhibit B
|
(Form of Assignment and Assumption)
|
Exhibit C
|
(Form of Notice of Commitment Increase)
|
Exhibit D-1
|
(Form of U.S. Tax Certificate for Foreign Lenders That Are Not Partnerships)
|
Exhibit D-2
|
(Form of U.S. Tax Certificate for Foreign Participants That Are Not Partnerships)
|
Exhibit D-3
|
(Form of U.S. Tax Certificate for Foreign Participants That Are Partnerships)
|
Exhibit D-4
|
(Form of U.S. Tax Certificate for Foreign Lenders That Are Partnerships)
|
BORROWER:
|
WESTERN GAS PARTNERS, LP
|
|
|
|
|
|
By:
|
Western Gas Holdings, LLC, its general partner
|
|
|
|
|
By:
|
/s/ Benjamin M. Fink
|
|
Name:
|
Benjamin M. Fink
|
|
Title:
|
President and Chief Executive Officer
|
ADMINISTRATIVE AGENT AND LENDER
:
|
WELLS FARGO BANK, NATIONAL ASSOCIATION
|
|
|
as Administrative Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Borden Tennant
|
|
Name:
|
Borden Tennant
|
|
Title:
|
Vice President
|
SYNDICATION AGENT AND LENDER
:
|
THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.,
|
|
|
as a Syndication Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Sherwin Brandford
|
|
Name:
|
Sherwin Brandford
|
|
Title:
|
Director
|
SYNDICATION AGENT AND LENDER
:
|
CITIBANK N.A.,
|
|
|
as a Syndication Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Maureen Maroney
|
|
Name:
|
Maureen Maroney
|
|
Title:
|
Vice President
|
SYNDICATION AGENT AND LENDER
:
|
MIZUHO BANK, LTD.,
|
|
|
as a Syndication Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Leon Mo
|
|
Name:
|
Leon Mo
|
|
Title:
|
Authorized Signatory
|
SYNDICATION AGENT AND LENDER
:
|
PNC BANK, NATIONAL ASSOCIATION,
|
|
|
as a Syndication Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Stephen Monto
|
|
Name:
|
Stephen Monto
|
|
Title:
|
SVP
|
SYNDICATION AGENT AND LENDER
:
|
U.S. BANK NATIONAL ASSOCIATION,
|
|
|
as a Syndication Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Patrick Jeffrey
|
|
Name:
|
Patrick Jeffrey
|
|
Title:
|
Vice President
|
DOCUMENTATION AGENT AND LENDER
:
|
BANK OF MONTREAL,
|
|
|
as a Documentation Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Melissa Guzmann
|
|
Name:
|
Melissa Guzmann
|
|
Title:
|
Director
|
DOCUMENTATION AGENT AND LENDER
:
|
BARCLAYS BANK PLC,
|
|
|
as a Documentation Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Sydney G. Dennis
|
|
Name:
|
Sydney G. Dennis
|
|
Title:
|
Director
|
DOCUMENTATION AGENT AND LENDER
:
|
BRANCH BANKING AND TRUST COMPANY,
|
|
|
as a Documentation Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ DeVon J. Lang
|
|
Name:
|
DeVon J. Lang
|
|
Title:
|
Senior Vice President
|
DOCUMENTATION AGENT AND LENDER
:
|
CAPITAL ONE, NATIONAL ASSOCIATION,
|
|
|
as a Documentation Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Stuart Gibson
|
|
Name:
|
Stuart Gibson
|
|
Title:
|
Managing Director
|
DOCUMENTATION AGENT AND LENDER
:
|
CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH,
|
|
|
as a Documentation Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Nupur Kumar
|
|
Name:
|
Nupur Kumar
|
|
Title:
|
Authorized Signatory
|
|
|
|
|
By:
|
/s/ Andrew Griffin
|
|
Name:
|
Andrew Griffin
|
|
Title:
|
Authorized Signatory
|
DOCUMENTATION AGENT AND LENDER
:
|
DEUTSCHE BANK AG NEW YORK BRANCH,
|
|
|
as a Documentation Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Ming K. Chu
|
|
Name:
|
Ming K. Chu
|
|
Title:
|
Director
|
|
|
|
|
By:
|
/s/ Virginia Cosenza
|
|
Name:
|
Virginia Cosenza
|
|
Title:
|
Vice President
|
DOCUMENTATION AGENT AND LENDER
:
|
MORGAN STANLEY BANK, N.A.,
|
|
|
as a Documentation Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Michael King
|
|
Name:
|
Michael King
|
|
Title:
|
Authorized Signatory
|
DOCUMENTATION AGENT AND LENDER
:
|
ROYAL BANK OF CANADA,
|
|
|
as a Documentation Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Jay T. Sartain
|
|
Name:
|
Jay T. Sartain
|
|
Title:
|
Authorized Signatory
|
DOCUMENTATION AGENT AND LENDER
:
|
THE BANK OF NOVA SCOTIA,
|
|
|
as a Documentation Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Donovan Crandall
|
|
Name:
|
Donovan Crandall
|
|
Title:
|
Managing Director
|
DOCUMENTATION AGENT AND LENDER
:
|
THE TORONTO-DOMINION BANK,
NEW YORK BRANCH,
|
|
|
as a Documentation Agent and a Lender
|
|
|
|
|
|
By:
|
/s/ Annie Dorval
|
|
Name:
|
Annie Dorval
|
|
Title:
|
Authorized Signatory
|
LENDER:
|
COMERICA BANK
|
|
|
|
|
|
By:
|
/s/ William B. Robinson
|
|
Name:
|
William B. Robinson
|
|
Title:
|
Senior Vice President
|
LENDER:
|
SOCIETE GENERALE
|
|
|
|
|
|
By:
|
/s/ Diego Medina
|
|
Name:
|
Diego Medina
|
|
Title:
|
Director
|
LENDER:
|
ZB, N.A. DBA AMEGY BANK
|
|
|
|
|
|
By:
|
/s/ G. Scott Collins
|
|
Name:
|
G. Scott Collins
|
|
Title:
|
Senior Vice President
|
|
|
|
|
By:
|
/s/ Miles Sedillo
|
|
Name:
|
Miles Sedillo
|
|
Title:
|
Assistant Vice President
|
LENDER:
|
STIFEL BANK & TRUST
|
|
|
|
|
|
By:
|
/s/ Daniel P. McDonald
|
|
Name:
|
Daniel. P. McDonald
|
|
Title:
|
Assistant Vice President
|
Lenders
|
Initial Amount of
Commitment |
Applicable Percentage
|
|||
Wells Fargo Bank, National Association
|
|
$100,000,000
|
|
6.666666667
|
%
|
The Bank of Tokyo-Mitsubishi UFJ, Ltd.
|
|
$100,000,000
|
|
6.666666667
|
%
|
Citibank, N.A.
|
|
$100,000,000
|
|
6.666666667
|
%
|
Mizuho Bank, Ltd.
|
|
$100,000,000
|
|
6.666666667
|
%
|
PNC Bank, National Association
|
|
$100,000,000
|
|
6.666666667
|
%
|
U.S. Bank National Association
|
|
$100,000,000
|
|
6.666666667
|
%
|
Bank of Montreal
|
|
$75,000,000
|
|
5.000000000
|
%
|
Barclays Bank PLC
|
|
$75,000,000
|
|
5.000000000
|
%
|
Branch Banking and Trust Company
|
|
$75,000,000
|
|
5.000000000
|
%
|
Capital One, National Association
|
|
$75,000,000
|
|
5.000000000
|
%
|
Credit Suisse AG, Cayman Islands Branch
|
|
$75,000,000
|
|
5.000000000
|
%
|
Deutsche Bank AG New York Branch
|
|
$75,000,000
|
|
5.000000000
|
%
|
Morgan Stanley Bank, N.A.
|
|
$75,000,000
|
|
5.000000000
|
%
|
Royal Bank of Canada
|
|
$75,000,000
|
|
5.000000000
|
%
|
The Bank of Nova Scotia
|
|
$75,000,000
|
|
5.000000000
|
%
|
The Toronto-Dominion Bank, New York Branch
|
|
$75,000,000
|
|
5.000000000
|
%
|
Comerica Bank
|
|
$52,500,000
|
|
3.500000000
|
%
|
Société Générale
|
|
$52,500,000
|
|
3.500000000
|
%
|
ZB, N.A. dba Amegy Bank
|
|
$30,000,000
|
|
2.000000000
|
%
|
Stifel Bank & Trust
|
|
$15,000,000
|
|
1.000000000
|
%
|
Total
|
|
$1,500,000,000
|
|
100.00000
|
%
|
Issuing Banks
|
Maximum LC Issuance Amount
|
||
Wells Fargo Bank, National Association
|
|
$50,000,000
|
|
The Bank of Tokyo-Mitsubishi UFJ, Ltd.
|
|
$10,000,000
|
|
Citibank, N.A.
|
|
$10,000,000
|
|
Mizuho Bank, Ltd.
|
|
$10,000,000
|
|
PNC Bank, National Association
|
|
$10,000,000
|
|
U.S. Bank National Association
|
|
$10,000,000
|
|
Total
|
|
$100,000,000
|
|
Senior Unsecured
Debt Rating
(S&P / Moody’s / Fitch)
|
Facility Fee
|
Eurodollar Margin
|
Base Rate Margin
|
Drawn Pricing (LIBOR)
|
>
BBB+ / Baa1 / BBB+
|
0.125%
|
1.000%
|
0.000%
|
1.125%
|
BBB / Baa2 / BBB
|
0.150%
|
1.100%
|
0.100%
|
1.250%
|
BBB- / Baa3 / BBB-
|
0.200%
|
1.300%
|
0.300%
|
1.500%
|
≤ BB+ / Ba1 / BB+
|
0.250%
|
1.500%
|
0.500%
|
1.750%
|
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.
|
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.
|
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.
|
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.
|
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.
|
6.
|
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.
|
7.
|
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.
|
8.
|
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.
|
9.
|
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.
|
10.
|
Amendment No. 1 to Purchase and Sale Agreement, dated as of May 22, 2017, by and between WGR Asset Holding Company LLC and Delaware Basin Midstream, LLC.
|
11.
|
Contribution Agreement, dated as of February 24, 2016, 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.
|
12.
|
Second Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 14, 2016. Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 14, 2016. Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated February 22, 2017. Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated November 9, 2017.
|
13.
|
Second Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated December 12, 2012.
|
14.
|
Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC and Anadarko Petroleum Corporation, dated as of May 14, 2008. 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. 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. 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. 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. 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.
|
15.
|
Services and Secondment Agreement between Western Gas Holdings, LLC and Anadarko Petroleum Corporation dated May 14, 2008. Amendment No. 1 to Services and Secondment Agreement between Western Gas Holdings, LLC and Anadarko Petroleum Corporation dated December 10, 2015.
|
16.
|
Tax Sharing Agreement by and among Anadarko Petroleum Corporation and Western Gas Partners, LP, dated as of May 14, 2008.
|
17.
|
Anadarko Petroleum Corporation Fixed Rate Note due 2038.
|
18.
|
Agreements for the gathering, processing, treatment, compression, storage or transportation of hydrocarbons, or the gathering and disposal of produced water, between Western Gas Partners, LP or one of its subsidiaries, on the one hand, and Anadarko Petroleum Corporation or one of its affiliates, on the other hand.
|
19.
|
Commodity Price Swap Agreements (the form of which is on file with the Securities and Exchange Commission) between the Partnership and Anadarko.
|
20.
|
Form of Indemnification Agreement by and between Western Gas Holdings, LLC, its Officers and Directors.
|
21.
|
Western Gas Partners, LP 2008 Long-Term Incentive Plan.
|
22.
|
Western Gas Partners, LP 2017 Long-Term Incentive Plan.
|
23.
|
Fourth Amended and Restated Indemnification Agreement, dated March 14, 2016, between Western Gas Holdings, LLC and Western Gas Resources, Inc.
|
24.
|
AMH Indemnification Agreement, dated March 3, 2014, between Western Gas Holdings, LLC and APC Midstream Holdings, LLC.
|
25.
|
KWC Indemnification Agreement, dated March 14, 2016, between Western Gas Holdings, LLC and Kerr-McGee Worldwide Corporation.
|
26.
|
Unit Purchase Agreement, dated October 28, 2014, by and among Western Gas Partners, LP, APC Midstream Holdings, LLC and Anadarko Petroleum Corporation.
|
|
WESTERN GAS PARTNERS, LP
|
|
|
|
|
|
By:
|
Western Gas Holdings, LLC,
its general partner
|
|
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
Amount of Loan
|
|
Type of Loan
|
|
Interest Rate
|
|
Amount of Principal Repaid
|
|
Notation Made by
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.
|
Assignor[s]: _______________________________
|
2.
|
Assignee[s]: _______________________________
|
3.
|
Borrower: Western Gas Partners, LP
|
4.
|
Administrative Agent:
|
5.
|
Credit Agreement: Third Amended and Restated Revolving Credit Agreement, dated as of February 15, 2018, among Western Gas Partners, LP, the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent, the Documentation Agents named therein, and the Syndication Agent named therein.
|
6.
|
Assigned Interest[s]:
|
Assignor[s]
5
|
Assignee[s]
6
|
Aggregate Amount of Commitment / Loans for all Lenders
7
|
Amount of Commitment / Loans Assigned
8
|
Percentage Assigned of Commitment /
Loans 8 |
CUSIP Number
|
|
|
$
|
$
|
%
|
|
|
|
$
|
$
|
%
|
|
|
|
$
|
$
|
%
|
|
By:
|
Western Gas Holdings, LLC,
its general partner |
WESTERN GAS PARTNERS, LP
|
|
|
|
|
|
By:
|
Western Gas Holdings, LLC,
its general partner
|
|
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
|
WESTERN GAS RESOURCES, INC.
|
|
|
|
|
|
|
|
|
By:
|
|
|
Name:
|
Michael C. Pearl
|
|
Title:
|
Vice President and Treasurer
|
|
WESTERN GAS HOLDINGS, LLC
|
|
|
|
|
|
|
|
|
By:
|
|
|
Name:
|
Philip H. Peacock
|
|
Title:
|
Vice President
|
GATHERER
|
|
SHIPPER
|
||
|
|
|
|
|
KERR-MCGEE GATHERING LLC
|
|
KERR-MCGEE OIL & GAS
ONSHORE LP
|
||
|
|
|
|
|
By:
|
/s/ Craig W. Collins
|
|
By:
|
/s/ Carrie L. Horton
|
Name:
|
Craig W. Collins
|
|
Name:
|
Carrie L. Horton
|
Title:
|
Senior Vice President &
Chief Operating Officer |
|
Title:
|
Vice President
|
|
|
Year Ended December 31,
|
||||||||||||||||||
thousands
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) before income taxes
|
|
$
|
583,084
|
|
|
$
|
610,666
|
|
|
$
|
59,739
|
|
|
$
|
495,729
|
|
|
$
|
292,559
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges
|
|
150,985
|
|
|
122,100
|
|
|
123,680
|
|
|
87,892
|
|
|
64,806
|
|
|||||
Distributions from equity investments
|
|
110,465
|
|
|
103,423
|
|
|
98,298
|
|
|
81,022
|
|
|
22,136
|
|
|||||
Amortization of capitalized interest
|
|
2,572
|
|
|
3,491
|
|
|
2,375
|
|
|
2,095
|
|
|
934
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Equity income, net – affiliates
|
|
85,194
|
|
|
78,717
|
|
|
71,251
|
|
|
57,836
|
|
|
22,948
|
|
|||||
Capitalized interest
|
|
6,826
|
|
|
5,562
|
|
|
8,318
|
|
|
9,832
|
|
|
11,945
|
|
|||||
Net income before taxes attributable to noncontrolling interest
|
|
10,735
|
|
|
10,963
|
|
|
10,101
|
|
|
14,025
|
|
|
10,816
|
|
|||||
Earnings
|
|
$
|
744,351
|
|
|
$
|
744,438
|
|
|
$
|
194,422
|
|
|
$
|
585,045
|
|
|
$
|
334,726
|
|
Fixed charges:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, excluding capitalized interest
|
|
$
|
149,212
|
|
|
$
|
120,483
|
|
|
$
|
122,190
|
|
|
$
|
86,598
|
|
|
$
|
63,742
|
|
Interest component of rent expense
|
|
1,773
|
|
|
1,617
|
|
|
1,490
|
|
|
1,294
|
|
|
1,064
|
|
|||||
Fixed charges
|
|
$
|
150,985
|
|
|
$
|
122,100
|
|
|
$
|
123,680
|
|
|
$
|
87,892
|
|
|
$
|
64,806
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Preferred unit distributions
(1)
|
|
$
|
7,453
|
|
|
$
|
45,784
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Combined fixed charges and preferred unit distributions
|
|
$
|
158,438
|
|
|
$
|
167,884
|
|
|
$
|
123,680
|
|
|
$
|
87,892
|
|
|
$
|
64,806
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
(2)
|
|
4.9x
|
|
|
6.1x
|
|
|
1.6x
|
|
|
6.7x
|
|
|
5.2x
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to combined fixed charges and preferred unit distributions
(2) (3)
|
|
4.7x
|
|
|
4.4x
|
|
|
1.6x
|
|
|
6.7x
|
|
|
5.2x
|
|
(1)
|
Represents the distributions associated with the Series A Preferred units issued in 2016. The Series A Preferred units converted into common units on a one-for-one basis in 2017.
|
(2)
|
These ratios were computed by dividing earnings by fixed charges and by combined fixed charges and preferred unit distributions, respectively. For this purpose, earnings include pre-tax income, plus fixed charges to the extent they affect current year earnings, amortization of capitalized interest and distributed income of equity investments, less equity income, noncontrolling interests in pre-tax income from subsidiaries that did not incur fixed charges, and interest capitalized during the year. Fixed charges include interest expensed and capitalized, amortized premiums, discounts and capitalized expenses related to indebtedness, and estimates of interest within rental expenses.
|
(3)
|
No preferred units were outstanding during the years ended December 31, 2015, 2014 and 2013.
|
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;
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(b)
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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;
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(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
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(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
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5.
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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):
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(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
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(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.
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/s/ Benjamin M. Fink
|
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Benjamin M. Fink
President and Chief Executive Officer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
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1.
|
I have reviewed this
annual
report on Form
10-K
of Western Gas Partners, LP (the “registrant”);
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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;
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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/ Jaime R. Casas
|
|
Jaime R. Casas
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, 2017
, 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 16, 2018
|
|
|
|
|
|
|
|
/s/ Benjamin M. Fink
|
|
|
Benjamin M. Fink
President and Chief Executive Officer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
|
|
|
February 16, 2018
|
|
|
|
|
|
|
|
/s/ Jaime R. Casas
|
|
|
Jaime R. Casas
Senior Vice President, Chief Financial Officer and Treasurer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|