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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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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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(Do not check if a smaller reporting company)
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Item
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Page
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1 and 2.
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1A.
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1B.
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3.
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4.
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5.
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6.
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7.
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7A.
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8.
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9.
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9A.
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9B.
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Item
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Page
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10.
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11.
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12.
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13.
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14.
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15.
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Owned and
Operated
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Operated
Interests
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Non-Operated
Interests
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Equity Interests
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Gathering systems
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11
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4
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5
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2
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Treating facilities
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12
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12
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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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5
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—
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2
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NGL pipelines
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2
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—
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—
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3
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Natural gas pipelines
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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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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 or Treating Capacity (MBbls/d)
(1)
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Average Gathering, Processing and Transportation Throughput (MMcf/d)
(2)
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Average Gathering, Treating and Transportation Throughput (MBbls/d)
(3)
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Rocky Mountains
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Gathering, Processing and Treating
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7,726
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4,624
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548,078
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3,377
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—
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2,252
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—
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Transportation
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1,726
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46
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43,634
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—
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—
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95
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28
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North-central Pennsylvania
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Gathering
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673
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404
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88,300
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—
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—
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770
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—
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Texas
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Gathering, Processing and Treating
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1,980
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891
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432,804
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1,260
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284
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903
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87
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Transportation
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1,175
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13
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40,895
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—
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—
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—
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69
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Total
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13,280
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5,978
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1,153,711
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4,637
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284
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4,020
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184
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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 and DBJV system throughput, 50.1% of Springfield gas gathering throughput, 22% of Rendezvous throughput and 14.81% of Fort Union throughput, but excludes throughput related to the Hugoton system (44 MMcf/d for the ten months ended October 31, 2016) prior to its divestiture in October 2016 (see
Acquisitions and Divestitures
within these Items 1 and 2).
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(3)
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Represents total throughput measured in barrels, consisting of throughput on our Chipeta NGL pipeline and an NGL line at our Brasada complex, our 50.1% share of average Springfield oil gathering system throughput, our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput and our 33.33% share of average FRP throughput. See
Properties
below for further descriptions of these systems.
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•
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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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Pursuing accretive acquisitions.
We expect to continue to pursue accretive acquisitions of midstream energy assets from Anadarko and third parties.
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Increasing third-party volumes to our systems.
We continue to actively market our midstream services to, and pursue strategic relationships with, third-party producers and customers with the intention of attracting additional volumes and/or expansion opportunities.
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Managing commodity price exposure.
We intend to continue limiting our direct exposure to commodity price changes and promote cash flow stability by pursuing a contract structure designed to mitigate exposure to a majority of the commodity price uncertainty through the use of fee-based contracts and fixed-price hedges.
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Maintaining investment grade metrics.
We intend to operate at appropriate leverage and distribution coverage levels in line with other partnerships in our sector that maintain investment grade credit ratings. By maintaining investment grade credit metrics, in part through staying within leverage ratios appropriate for investment-grade partnerships, we believe that we will be able to pursue strategic acquisitions and large growth projects at a lower cost of fixed-income capital, which would enhance our accretion and overall return.
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Affiliation with Anadarko.
We believe Anadarko is motivated to promote and support the successful execution of our business plan and to use its relationships throughout the energy industry, including those with producers and customers in the United States, to pursue projects that help to enhance the value of our business. See
Our Relationship with Anadarko Petroleum Corporation
below.
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Commodity price and volumetric risk mitigation.
Our cash flows are relatively 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,
2016
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99%
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 1, 2016, we renewed our commodity price swap agreements with Anadarko for the DJ Basin complex and the MGR assets through December 31, 2017. See
Risk Factors
under Part I, Item 1A and
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K. In addition, we mitigate volumetric risk by entering into contracts with cost of service or demand charge structures. For the year ended December 31,
2016
, and excluding throughput measured in barrels, 54% of our throughput was subject to demand charges and 27% of our throughput was contracted under a cost of service model.
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Liquidity to pursue expansion and acquisition opportunities
.
We believe our operating cash flows, borrowing capacity, long-term relationships and reasonable access to debt and equity capital markets provide us with the liquidity to competitively pursue acquisition and expansion opportunities and to execute our strategy across capital market cycles. As of December 31,
2016
, we had
no
outstanding borrowings under our RCF and
$4.9 million
in outstanding letters of credit issued under our $1.2 billion RCF.
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Substantial presence in basins with historically strong producer economics.
Certain of our systems are in areas, such as the Delaware and DJ Basins, and the Eagleford shale, which have historically seen robust producer activity and are considered to have some of the most favorable producer returns for onshore North America. Our assets in these areas serve production where the hydrocarbons contain not only natural gas, but also oil, condensate and NGLs. In addition, our interest in the Anadarko-Operated Marcellus gathering systems serve dry gas production from the Marcellus shale, which is considered to have some of the most abundant low-cost, dry gas reserves due to the overall scale and quality of the underlying resource. See
Properties
below for further asset descriptions and
Note 14—Subsequent Events
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K.
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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 six third-party acquisitions, with an aggregate value of $5.6 billion (inclusive of the forecasted cash payment of
$56.5 million
for the acquisition of DBJV in March 2020, see
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-K). Our management team has demonstrated its ability to identify, evaluate, negotiate, consummate and integrate strategic acquisitions and expansion projects, and it intends to use its experience and reputation to continue to grow the Partnership through accretive acquisitions, focusing on opportunities to improve throughput volumes and cash flows.
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Gathering.
At the initial stages of the midstream value chain, a network of typically smaller diameter pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow gathering of additional production without significant incremental capital expenditures.
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Stabilization.
Stabilization is a process that separates the heavier hydrocarbons (which also serve as 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 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 both throughout the pipeline network and at major market centers to better accommodate seasonal demand and daily supply-demand shifts. We do not currently offer storage services.
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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 byproduct of crude oil and natural gas production, produced water must be recycled or disposed of in order to maintain production. Produced water disposal wells and related facilities remove hydrocarbon products and other sediments from the produced water in compliance with applicable regulations and re-inject it into an underground formation.
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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 gas, is returned to the producer. Since some of the gas is used and removed during processing, the processor compensates the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas utilized. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.
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Firm.
Firm service requires the reservation of capacity by a customer between certain receipt and delivery points or within a processing facility. Firm customers generally pay a demand or capacity reservation fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus, in specific cases, a usage fee based on the volumes gathered, processed or transported.
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Interruptible.
Interruptible service is typically short-term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume actually gathered, processed or transported. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and, as such, customers receiving services under interruptible contracts are not assured capacity.
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Location
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Asset
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Type
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Processing / Treating Plants
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Processing / Treating Capacity (MMcf/d)
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Compressors
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Compression Horsepower
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Gathering Systems
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Pipeline Miles
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Northeast Wyoming
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Bison
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Treating
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3
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450
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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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40
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41,919
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1
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1,497
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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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188
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Southwest Wyoming
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Granger complex
(2)
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Gathering & Processing
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4
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500
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44
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48,617
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1
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834
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Southwest Wyoming
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Red Desert complex
(3)
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Gathering & Processing
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1
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125
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33
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58,129
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1
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1,122
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Southwest Wyoming
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Rendezvous
(4)
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Gathering
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—
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—
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5
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7,485
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1
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338
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Total
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14
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1,433
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140
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178,884
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6
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4,294
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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 for the year ended December 31,
2016
. The largest customer provided 78% of the throughput during the year ended December 31,
2016
.
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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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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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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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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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Colorado Interstate Gas Company LLC’s pipeline (“CIG”);
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Tallgrass Interstate Gas Transmission system’s pipeline (“TIGT”); and
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Wyoming Interstate Company’s pipeline (“WIC”).
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Customers.
Gas gathered and processed through the Hilight system is from numerous third-party customers, with the six largest producers providing 79% of the system throughput during the year ended December 31,
2016
.
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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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•
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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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Customers.
Gas gathered and processed through the Newcastle system is from 11 third-party customers, with the largest three producers providing 79% of the system throughput during the year ended December 31,
2016
. The largest producer provided 48% of the throughput during the year ended December 31,
2016
.
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Supply.
The Newcastle gathering system and plant primarily service gas production from the Clareton and Finn-Shurley fields in Weston County, Wyoming. Due to infill drilling and enhanced production techniques, producers have continued to maintain production levels.
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Delivery points.
Propane products from the Newcastle plant are typically sold locally by truck, and the butane/gasoline mix products are transported to the Hilight plant for further fractionation. Residue from the Newcastle system is delivered into Black Hills Corporation’s intrastate pipeline for transport, distribution and sale.
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•
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Customers.
For the year ended December 31,
2016
, 89% of the Granger complex throughput was from five third-party customers and 2% was from Anadarko.
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Supply.
The Granger complex is supplied by the Moxa Arch and the Jonah and Pinedale Anticline fields. The Granger gas gathering system had 593 active receipt points as of December 31,
2016
.
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Delivery points.
The residue from the Granger complex can be delivered to the following major pipelines:
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◦
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CIG;
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◦
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Berkshire Hathaway Energy’s Kern River pipeline (“Kern River pipeline”) via a connect with Tesoro Logistics LP’s (“Tesoro”) Rendezvous pipeline (“Rendezvous pipeline”);
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◦
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Questar Pipeline Company’s pipeline (“Questar pipeline”);
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◦
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Questar Overthrust Pipeline;
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◦
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The Williams Companies, Inc.’s Northwest Pipeline (“NWPL”);
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◦
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our OTTCO pipeline; and
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◦
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our Mountain Gas Transportation LLC pipeline.
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•
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Customers.
For the year ended December 31,
2016
, 61% of the Red Desert complex throughput was from six third-party customers and 7% was from Anadarko.
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•
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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.
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•
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Delivery points.
Residue from the Red Desert complex is delivered to CIG and WIC, while NGLs are delivered to MAPL, as well as to truck and rail loading facilities.
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•
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Customers.
Tesoro and Anadarko are the only firm customers on the Rendezvous gathering system. To the extent capacity on the system is not used by those customers, it is available to third parties under interruptible agreements.
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•
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Supply and delivery points.
The Rendezvous gathering system provides high pressure gathering service for gas from the Jonah and Pinedale Anticline fields and delivers to our Granger plant, as well as Tesoro’s Blacks Fork gas processing plant, which connects to the Questar pipeline, NWPL and the Kern River pipeline via the Rendezvous pipeline.
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Location
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Asset
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Type
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Processing / Treating Plants
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Processing / Treating Capacity (MMcf/d)
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Compressors
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Compression Horsepower
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Gathering Systems
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Pipeline Miles
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||||||
Colorado
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DJ Basin complex
(1)
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Gathering, Processing & Treating
|
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9
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919
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118
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264,044
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2
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3,205
|
|
Utah
|
|
Chipeta
(2)
|
|
Processing
|
|
4
|
|
|
980
|
|
|
18
|
|
|
84,007
|
|
|
—
|
|
|
—
|
|
Utah
|
|
Clawson
|
|
Gathering & Treating
|
|
2
|
|
|
20
(3)
|
|
|
5
|
|
|
6,310
|
|
|
1
|
|
|
31
|
|
Utah
|
|
Helper
|
|
Gathering & Treating
|
|
3
|
|
|
25
(3)
|
|
|
11
|
|
|
13,475
|
|
|
1
|
|
|
130
|
|
Total
|
|
|
|
|
|
18
|
|
|
1,944
|
|
|
152
|
|
|
367,836
|
|
|
4
|
|
|
3,366
|
|
(1)
|
The DJ Basin complex includes the Platte Valley, Fort Lupton, Fort Lupton JT, Hambert JT, and Lancaster Trains I and II processing plants, the Platteville amine treating plant, and the Wattenberg gathering system.
|
(2)
|
We are the managing member of and own a 75% interest in Chipeta. Chipeta owns the Chipeta processing complex and the Natural Buttes refrigeration plant.
|
(3)
|
At current carbon dioxide
levels and operating conditions.
|
•
|
Customers.
Anadarko is the largest customer with 70% of the DJ Basin complex throughput for the year ended December 31,
2016
. The balance of the throughput was from various third-party customers, with the largest providing 15% of the throughput.
|
•
|
Supply.
There were 2,598 active receipt points connected to the DJ Basin complex as of December 31,
2016
. The DJ Basin complex is primarily supplied by the Wattenberg field, in which Anadarko controls 749,000 gross acres. Anadarko drilled 97 wells and completed 204 wells during the year ended December 31,
2016
.
|
•
|
Delivery points.
As of December 31,
2016
, the DJ Basin complex had the following delivery points for gas not processed within the DJ Basin complex:
|
◦
|
Anadarko’s Wattenberg plant inlet; and
|
◦
|
Various interconnections with DCP Midstream LP’s (“DCP”) gathering and processing system.
|
•
|
Customers.
Anadarko is the largest customer at Chipeta with 77% of the system throughput for the year ended December 31,
2016
. The balance of throughput during the year ended December 31,
2016
was from 9 third-party customers.
|
•
|
Supply.
The Chipeta complex is well positioned to access Anadarko and third-party production in the Uinta Basin where Anadarko controls 255,000 gross acres. Chipeta’s inlet is connected to Anadarko’s Natural Buttes gathering system, the Questar pipeline and Three Rivers Gathering, LLC’s system, which is owned by Ute Energy and another third party.
|
•
|
Delivery points.
The Chipeta plant delivers NGLs to MAPL, which provides transportation through Enterprise’s Seminole pipeline (“Seminole pipeline”) and TEP’s pipeline in West Texas and ultimately to the NGL fractionation and storage facilities in Mont Belvieu, Texas. The Chipeta plant has residue gas delivery points through the following pipelines delivering to markets throughout the Rockies and Western United States:
|
◦
|
CIG;
|
◦
|
Questar pipeline; and
|
◦
|
WIC.
|
•
|
Customers.
Anadarko is the only shipper on the Clawson gathering system.
|
•
|
Supply.
The Clawson Springs field covers 7,600 gross acres and produces primarily from the Ferron Coal play.
|
•
|
Delivery points.
The Clawson gathering system delivers into the Questar pipeline. The Questar pipeline provides transportation to regional markets in Wyoming, Colorado and Utah and also delivers into the Kern River pipeline, which provides transportation to markets in the Western United States, primarily California.
|
•
|
Customers.
Anadarko is the only shipper on the Helper gathering system.
|
•
|
Supply.
The Helper and the Cardinal Draw fields are Anadarko-operated coal-bed methane developments on the southwestern edge of the Uinta Basin that produce from the Ferron Coal play. Anadarko owns 19,000 gross acres in the Helper field and 16,000 gross acres in the Cardinal Draw field.
|
•
|
Delivery points.
The Helper gathering system delivers into the Questar pipeline. The Questar pipeline provides transportation to regional markets in Wyoming, Colorado and Utah and also delivers into the Kern River pipeline, which provides transportation to markets in the Western United States, primarily California.
|
Location
|
|
Asset
|
|
Type
|
|
Compressors
|
|
Compression Horsepower
|
|
Gathering Systems
|
|
Pipeline Miles
|
||||
North-central Pennsylvania
|
|
Non-Operated Marcellus
(1)
|
|
Gathering
|
|
31
|
|
|
81,400
|
|
|
2
|
|
|
531
|
|
North-central Pennsylvania
|
|
Anadarko-Operated Marcellus
(2)
|
|
Gathering
|
|
5
|
|
|
6,900
|
|
|
3
|
|
|
142
|
|
Total
|
|
|
|
|
|
36
|
|
|
88,300
|
|
|
5
|
|
|
673
|
|
(1)
|
WES owns a 33.75% interest in the Non-Operated Marcellus Interest gathering systems, with a third party serving as the operator.
|
(2)
|
WES owns a 33.75% interest in the Anadarko-Operated Marcellus Interest gathering systems, with Anadarko serving as the operator.
|
•
|
Customers.
As of December 31,
2016
, in addition to Anadarko, the Non-Operated Marcellus Interest gathering systems had seven priority shippers on its Rome gathering system and eight priority shippers on its Liberty gathering system. Also as of December 31,
2016
, in addition to Anadarko, the Anadarko-Operated Marcellus Interest gathering systems had six priority shippers. For the year ended December 31,
2016
, Anadarko represented 18% and 43% of throughput on the Non-Operated Marcellus Interest gathering systems and the Anadarko-Operated Marcellus Interest gathering systems, respectively. Capacity not used by priority shippers is available to third parties.
|
•
|
Supply and delivery points.
As of December 31,
2016
, Anadarko had a working interest in over 533,000 gross acres within the Marcellus shale. On December 21, 2016, Anadarko announced it had agreed to sell its operated and non-operated upstream assets and operated midstream assets (excluding the Partnership’s interests) in the Marcellus shale to a third party, including approximately 195,000 net acres. The transaction is expected to close in the first quarter of 2017, subject to standard closing conditions and adjustments. The Non-Operated Marcellus Interest gathering systems have access to Transcontinental Gas Pipeline Company, LLC’s pipeline (“TRANSCO”), Tennessee Gas Pipeline Company, LLC’s pipeline and Millennium Pipeline Company, LLC’s pipeline. The Anadarko-Operated Marcellus Interest gathering systems have access to TRANSCO.
|
Location
|
|
Asset
|
|
Type
|
|
Processing / Treating Plants
|
|
Processing / Treating Capacity (MMcf/d)
|
|
Processing / Treating Capacity (MBbls/d)
|
|
Compressors
(1)
|
|
Compression Horsepower
(1)
|
|
Gathering Systems
|
|
Pipeline Miles
|
|||||||
East Texas
|
|
Mont Belvieu JV
(2)
|
|
Processing
|
|
2
|
|
|
—
|
|
|
170
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
South Texas
|
|
Brasada complex
|
|
Gathering, Processing & Treating
|
|
3
|
|
|
200
|
|
|
15
|
|
|
14
|
|
|
30,450
|
|
|
1
|
|
|
57
|
|
South Texas
|
|
Springfield system
(3)
|
|
Gathering and Treating
|
|
3
|
|
|
—
|
|
|
75
|
|
|
107
|
|
|
172,216
|
|
|
2
|
|
|
811
|
|
West Texas
|
|
Haley
|
|
Gathering
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
15,300
|
|
|
1
|
|
|
178
|
|
West Texas
|
|
DBM complex
(4)
|
|
Gathering, Processing & Treating
|
|
5
|
|
|
700
|
|
|
18
|
|
|
84
|
|
|
149,000
|
|
|
1
|
|
|
357
|
|
West Texas
|
|
DBJV system
(5)
|
|
Gathering & Treating
|
|
9
|
|
|
360
|
|
|
6
|
|
|
50
|
|
|
65,838
|
|
|
1
|
|
|
577
|
|
Total
|
|
|
|
|
|
22
|
|
|
1,260
|
|
|
284
|
|
|
265
|
|
|
432,804
|
|
|
6
|
|
|
1,980
|
|
(1)
|
Includes owned, rented and leased compressors and compression horsepower.
|
(2)
|
We own a 25% interest in the Mont Belvieu JV, which owns two NGL fractionation trains. A third party serves as the operator.
|
(3)
|
We own a 50.1% interest in the Springfield system and serve as the operator.
|
(4)
|
Excludes 1,400 gpm of amine treating capacity at the DBM complex. Train VI is currently under construction. See
Assets Under Development
below.
|
(5)
|
We own a 50% interest in the DBJV system and serve as the operator.
|
•
|
Customers.
The Mont Belvieu JV does not directly contract with customers, but rather is allocated volumes from Enterprise based on the available capacity of the other trains at Enterprise’s NGL fractionation complex in Mont Belvieu, Texas.
|
•
|
Supply and delivery points.
Enterprise receives volumes at its fractionation complex in Mont Belvieu, Texas via a large number of pipelines that terminate there, including the Seminole pipeline, Skelly-Belvieu Pipeline Company, LLC’s pipeline, 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.
Anadarko provides 100% of the throughput to the Brasada complex. Anadarko delivers gas and NGLs to the plant on behalf of itself and its upstream joint interest owners.
|
•
|
Supply.
Brasada is supplied from Anadarko’s production in the Eagleford shale, in which Anadarko controlled 345,000 gross acres. As noted above, in January 2017, Anadarko announced the sale of its Eagleford shale upstream assets to third parties.
|
•
|
Delivery points.
The facility delivers residue gas into the Eagle Ford Midstream system operated by NET Midstream, LLC. It delivers stabilized condensate into Plains All American Pipeline and NGLs into the South Texas NGL Pipeline System operated by Enterprise.
|
•
|
Customers.
Anadarko’s production represented 49% of the Springfield gas gathering system’s throughput, and 47% of the Springfield oil gathering system’s throughput for the year ended December 31,
2016
. The remaining throughput was attributable to three third-party producers for the gas gathering system and the oil gathering system.
|
•
|
Supply.
Supply of gas and oil comes from Anadarko’s production in the Eagleford shale, in which Anadarko controlled 345,000 gross acres. As noted above, in January 2017, Anadarko announced the sale of its Eagleford shale upstream assets to third parties.
|
•
|
Delivery points.
The gas gathering system delivers rich gas to our Brasada complex and to processing plants operated by Enterprise, Energy Transfer Partners, LP (“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’s Pipeline.
|
•
|
Customers.
Anadarko’s production represented 83% of the Haley gathering system’s throughput for the year ended December 31,
2016
. The remaining throughput was attributable to two third-party producers.
|
•
|
Supply.
As of December 31,
2016
, Anadarko held an interest in over 580,000 gross acres in the greater Delaware Basin, a portion of which is gathered by the Haley gathering system.
|
•
|
Delivery points.
The Haley gathering system provides both lean and rich gas gathering service. The lean service delivery point is into Enterprise GC, LLC’s pipeline for ultimate delivery into ETP’s Oasis pipeline (the “Oasis pipeline”). The rich service system delivery point is into a high pressure gathering line (the “Avalon Express pipeline”), which is part of our DBJV system. The Avalon Express pipeline can deliver gas into either the Bone Spring Gas Processing plant (the “Bone Spring plant”) or the Mi Vida Gas Processing plant (the “Mi Vida plant”), both of which are partially owned by Anadarko. Downstream pipelines at the plant tailgates include the Oasis and Transwestern pipelines at the Bone Spring plant and the Oasis pipeline at the Mi Vida plant. These downstream pipelines provide transportation to both the Waha Hub and Houston Ship Channel markets.
|
•
|
Customers.
Gas gathered and processed through the DBM complex is primarily from third-party producers, with the three largest producers providing 46% of the system throughput for the year ended December 31,
2016
.
|
•
|
Supply.
Supply of gas and NGLs for the complex comes from production from the Delaware Sands, Avalon Shale, Bone Spring and Wolfcamp formations in the Delaware Basin portion of the Permian Basin. Anadarko holds an interest in over 580,000 gross acres within the Delaware Basin.
|
•
|
Delivery points.
Residue gas produced at the facility is delivered to an interconnect with the El Paso Natural Gas pipeline. NGL production is delivered into both the Sand Hills pipeline and Lone Star NGL LLC’s pipeline.
|
•
|
Customers.
Anadarko’s production represented 80% of the DBJV system’s throughput for the year ended December 31,
2016
. The remaining throughput was attributable to one third-party producer.
|
•
|
Supply.
The system gathers lean Penn gas, as well as liquids-rich Bone Spring, Avalon and Wolfcamp gas.
|
•
|
Delivery points.
Avalon, Bone Spring and Wolfcamp gas is dehydrated, compressed and delivered to both the Bone Spring plant and the Mi Vida plant for processing, while lean Penn gas is delivered into Enterprise GC, LP’s pipeline. Residue gas from the Bone Spring and Mi Vida plants is delivered into the Oasis pipeline or Transwestern pipeline.
|
Location
|
|
Asset
|
|
Type
|
|
Compressors /
Pump Stations
|
|
Operational Horsepower
|
|
Pipeline Miles
|
|||
Northeast Wyoming
|
|
MIGC
(1)
|
|
Gas
|
|
3
|
|
|
6,660
|
|
|
240
|
|
Southwest Wyoming
|
|
OTTCO
|
|
Gas
|
|
1
|
|
|
3,174
|
|
|
217
|
|
Utah
|
|
GNB NGL
(1)
|
|
NGL
|
|
—
|
|
|
—
|
|
|
32
|
|
Colorado, Kansas, Oklahoma
|
|
White Cliffs
(1) (2)
|
|
Oil
|
|
24
|
|
|
33,800
|
|
|
1,054
|
|
Colorado, Oklahoma, Texas
|
|
FRP
(1) (3)
|
|
NGL
|
|
6
|
|
|
12,000
|
|
|
447
|
|
Texas, Oklahoma
|
|
TEG
(3)
|
|
NGL
|
|
19
|
|
|
1,895
|
|
|
117
|
|
Texas
|
|
TEP
(1) (3)
|
|
NGL
|
|
12
|
|
|
27,000
|
|
|
593
|
|
Texas
|
|
Ramsey Residue Lines
(1)
|
|
Gas
|
|
—
|
|
|
—
|
|
|
18
|
|
Total
|
|
|
|
|
|
65
|
|
|
84,529
|
|
|
2,718
|
|
(1)
|
MIGC, GNB NGL, White Cliffs, 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.
Anadarko is the largest firm shipper on the MIGC system, with 89% of the throughput for the year ended December 31,
2016
. The remaining throughput on the MIGC system was from 16 third-party shippers. MIGC is certificated for 175 MMcf/d of firm transportation capacity.
|
•
|
Supply.
MIGC receives gas from various coal-bed methane gathering systems in the Powder River Basin and the Hilight system, as well as from WBI Energy Transmission, Inc. on the north end of the transportation system.
|
•
|
Delivery points.
MIGC volumes can be redelivered to the hub in Glenrock, Wyoming, which has access to the following interstate pipelines:
|
◦
|
CIG;
|
◦
|
TIGT; and
|
◦
|
WIC.
|
•
|
Customers.
For the year ended December 31,
2016
, 11% of OTTCO’s throughput was from Anadarko. The remaining throughput on the OTTCO transportation system was from two third-party shippers. Revenues on the OTTCO transportation system are generated from contract demand charges and volumetric fees paid by shippers under firm and interruptible gas transportation agreements.
|
•
|
Supply and delivery points.
Supply points to the OTTCO transportation system include approximately 50 wellheads, the Granger complex and ExxonMobil Corporation’s Shute Creek plant, which are supplied by the eastern portion of the Greater Green River Basin, the Moxa Arch and the Jonah and Pinedale Anticline fields. Primary delivery points include the Red Desert complex, two third-party industrial facilities and an inactive interconnection with the Kern River pipeline.
|
•
|
Customers.
Anadarko was the only shipper on the GNB NGL pipeline for the year ended December 31,
2016
.
|
•
|
Supply.
The GNB NGL pipeline receives NGLs from Chipeta’s gas processing facility and Tesoro’s Stagecoach/Iron Horse gas processing complex.
|
•
|
Delivery points.
The GNB NGL pipeline delivers NGLs to MAPL, which provides transportation through the Seminole pipeline and TEP in West Texas, and ultimately to NGL fractionation and storage facilities in Mont Belvieu, Texas.
|
•
|
Customers.
The White Cliffs pipeline had multiple committed shippers, including Anadarko, during the year ended December 31,
2016
. In addition, other parties may ship on the White Cliffs pipeline at FERC-based rates. The White Cliffs dual pipeline system provides 150 MBbls/d of crude takeaway capacity from Platteville, Colorado to Cushing, Oklahoma. White Cliffs is currently undergoing an expansion project that will increase the pipeline’s capacity to approximately 215 MBbls/d. This expansion project is scheduled to be completed early in the second quarter of 2017.
|
•
|
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.
|
•
|
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 our Lancaster plant, which is within the DJ Basin complex) (see
Rocky Mountains—Colorado and Utah
within these Items 1 and 2). FRP connects to TEP near Skellytown, Texas. During the year ended December 31,
2016
, FRP had multiple committed shippers, including Anadarko, and provides capacity for other shippers at the posted FERC tariff rate.
|
•
|
Texas Express Gathering.
TEG consists of two NGL gathering systems that provide plants in North Texas, the Texas panhandle and West Oklahoma with access to NGL takeaway capacity on TEP. TEG had one committed shipper during the year ended December 31,
2016
.
|
•
|
Texas Express Pipeline.
TEP delivers to NGL fractionation and storage facilities in Mont Belvieu, Texas. At Skellytown, Texas, TEP is supplied with NGLs from other pipelines including FRP and MAPL. TEP had multiple committed shippers, including Anadarko, during the year ended December 31,
2016
and provides capacity for other shippers at the posted FERC tariff rates.
|
•
|
DBM Train VI:
The 200 MMcf/d cryogenic train is under construction and is expected to be completed during the fourth quarter of 2017. The DBM complex will have 900 MMcf/d processing capacity upon completion.
|
•
|
Mentone gas plant:
We have sanctioned a new gas processing plant which will be located in Loving County, Texas. This plant will have connections to the DBJV system in West Texas. Engineering and procurement of equipment has begun and the construction of the initial cryogenic trains (Mentone Trains I and II) is expected to begin during the fourth quarter of 2017.
|
•
|
Produced-water disposal systems:
The River Reeves and Silvertip systems located in Reeves County and Loving County, Texas, respectively, are currently under construction with expected in-service dates during the second quarter of 2017. The River Reeves and Silvertip systems are expected to have produced-water disposal capacities of 30 MBbls/d and 60 MBbls/d, respectively. The two facilities currently have contracts in place with a subsidiary of Anadarko.
|
System
|
|
Competitor(s)
|
Anadarko-Operated Marcellus Interest gathering systems
|
|
ETP and National Fuel Gas Midstream Corporation
|
Bison facility
|
|
Thunder Creek Gas Services, LLC and Fort Union (treating only)
|
Brasada complex
|
|
Enterprise, ETP, Targa Resources, LP, Kinder Morgan, Inc., Plains All American Pipeline and Howard Energy Partners
|
Chipeta complex
|
|
Tesoro and Kinder Morgan, Inc.
|
DBJV system
|
|
ETP, Outrigger Midstream, Enterprise GC, LP, EagleClaw Midstream Ventures LLC, Enlink Midstream, LP and Vaquero Midstream LLC
|
DBM complex
|
|
ETP, Outrigger Midstream, Enterprise GC, LP, EagleClaw Midstream Ventures LLC, Enlink Midstream, LP and Vaquero Midstream LLC
|
DJ Basin complex
|
|
DCP and AKA Energy Group, LLC
|
Fort Union
|
|
Bison treating facility (carbon dioxide treating services only), MIGC, Thunder Creek Gas Services, LLC and TransCanada Corporation
|
Granger complex
|
|
Williams Field Services, Enterprise/Jonah Gas Gathering Company and Tesoro
|
Haley system
|
|
ETP, Outrigger Midstream, Enterprise GC, LP
|
Helper and Clawson systems
|
|
XTO Energy
|
Hilight system
|
|
DCP, ONEOK Gas Gathering Company, Thunder Creek Gas Services, LLC, Crestwood-Access, Tallgrass Energy Partners, LP and Agave Energy Company
|
Mont Belvieu JV
|
|
Targa Resources LP, Phillips 66, Lone Star NGL LLC and ONEOK Partners, LP
|
Newcastle system
|
|
DCP
|
Non-Operated Marcellus Interest gathering systems
|
|
ETP
|
Red Desert complex
|
|
Williams Field Services and Tesoro
|
Rendezvous
|
|
No significant direct competition
|
Springfield system
|
|
Enterprise, ETP, Targa Resources, LP, Kinder Morgan, Inc., Plains All American Pipeline, Southcross Energy Partners, L.P., Williams Field Services 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, imposes various pre-construction, monitoring, and reporting requirements, 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 ensures 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.
|
•
|
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 our 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 and transportation agreements and our $260.0 million note receivable from Anadarko;
|
•
|
the timing, amount and terms of future issuances of equity and debt securities; and
|
•
|
other factors discussed below and elsewhere in this Item 1A, under the caption
Critical Accounting 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 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 in order to minimize emissions of carbon dioxide, a GHG; 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 energy 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 or with respect to any outstanding preferred units; 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 energy business; or
|
•
|
enter into a merger, consolidate, liquidate, wind up or dissolve.
|
•
|
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
|
•
|
our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flows required to make interest payments on our debt;
|
•
|
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
|
•
|
our flexibility in responding to changing business and economic conditions may be limited.
|
•
|
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 under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The EPA is expected to make final geographical attainment designations and issue final non-attainment area requirements pursuant to this NAAQS rule by late 2017, and any designations or requirements that result in 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. Moreover, states are expected to implement more stringent regulations, which could apply to our operations. Compliance with this rule could, among other things, require installation of new emission controls on some of our equipment, result 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, that 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 published by the EPA in 2012, known as Subpart OOOO, by using certain equipment specific emissions control practices with respect 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. Moreover, in November 2016, the EPA issued a final Information Collection Request seeking information about methane emissions from facilities and operators in the oil and natural gas industry. The EPA has indicated that it intended to use the information from this request to develop Existing Source Performance Standards for the oil and gas industry. Compliance with this rule 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 Greenhouse Gas Emissions.
The U.S. Congress and the EPA, in addition to some state and regional efforts, 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. Furthermore, the EPA has passed a rule, known as the Clean Power Plan, to limit GHGs from power plants, but on February 9, 2016, the U.S. Supreme Court stayed this rule while it is being challenged in the federal D.C. Circuit Court of Appeals. If this rule survives legal challenge, then depending on the methods used to implement this rule, it could reduce demand for the oil and natural gas our customers produce or increase the cost of electricity for our operations. 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 that requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. Although this international agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. The adoption and implementation of any federal or state legislation or regulations that restrict emissions of GHGs or other air emissions could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows.
|
•
|
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 as a result of the malfunction of equipment or facilities;
|
•
|
fires and explosions (for example, see
Items Affecting Comparability of Our Financial Results
, under Part II, Item 7 of this Form 10-K for a discussion of the incident at our DBM complex); and
|
•
|
other hazards that could also result in personal injury, loss of life, pollution, natural resource damages and/or suspension of operations.
|
•
|
Neither our partnership agreement nor any other agreement requires Anadarko to pursue a business strategy that favors us.
|
•
|
Anadarko is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to parties other than us.
|
•
|
Our general partner is allowed to take into account the interests of parties other than us, such as Anadarko, in resolving conflicts of interest.
|
•
|
The officers of our general partner will also devote significant time to the business of Anadarko and will be compensated by Anadarko accordingly. 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
|
||||||||
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
|
|
||||
2015
|
|
|
|
|
|
|
|
||||||||
High Price
|
$
|
54.35
|
|
|
$
|
65.23
|
|
|
$
|
74.30
|
|
|
$
|
74.45
|
|
Low Price
|
36.70
|
|
|
43.88
|
|
|
62.21
|
|
|
62.71
|
|
||||
Distribution per common unit
|
0.800
|
|
|
0.775
|
|
|
0.750
|
|
|
0.725
|
|
|
|
Acquisition Date
|
|
Percentage Acquired
|
|
Affiliate or Third-party Acquisition
|
|
Initial assets
(1)
|
|
05/14/2008
|
|
100
|
%
|
|
Anadarko
|
Powder River assets
(2)
|
|
12/19/2008
|
|
Various
(2)
|
|
|
Anadarko
|
Chipeta
|
|
07/01/2009
|
|
51
|
%
|
|
Anadarko
|
Granger
|
|
01/29/2010
|
|
100
|
%
|
|
Anadarko
|
Wattenberg
|
|
08/02/2010
|
|
100
|
%
|
|
Anadarko
|
White Cliffs
(3)
|
|
09/28/2010
|
|
10
|
%
|
|
Various
(3)
|
Platte Valley
|
|
02/28/2011
|
|
100
|
%
|
|
Third party
|
Bison
|
|
07/08/2011
|
|
100
|
%
|
|
Anadarko
|
MGR
|
|
01/13/2012
|
|
100
|
%
|
|
Anadarko
|
Chipeta
(4)
|
|
08/01/2012
|
|
24
|
%
|
|
Anadarko
|
Non-Operated Marcellus Interest
|
|
03/01/2013
|
|
33.75
|
%
|
|
Anadarko
|
Anadarko-Operated Marcellus Interest
|
|
03/08/2013
|
|
33.75
|
%
|
|
Third party
|
Mont Belvieu JV
|
|
06/05/2013
|
|
25
|
%
|
|
Third party
|
OTTCO
|
|
09/03/2013
|
|
100
|
%
|
|
Third party
|
TEFR Interests
(5)
|
|
03/03/2014
|
|
Various
(5)
|
|
|
Anadarko
|
DBM
|
|
11/25/2014
|
|
100
|
%
|
|
Third party
|
DBJV
|
|
03/02/2015
|
|
100
|
%
|
|
Anadarko
|
Springfield
|
|
03/14/2016
|
|
100
|
%
|
|
Anadarko
|
(1)
|
Concurrently with the closing of our IPO, Anadarko contributed the initial assets to us.
|
(2)
|
Acquired the Powder River assets, which included (i) the Hilight system, (ii) a 50% interest in the Newcastle system and (iii) a 14.81% membership interest in Fort Union.
|
(3)
|
Acquired a 10% interest in White Cliffs, which consisted of a 9.6% third-party interest and a 0.4% interest from Anadarko.
|
(4)
|
Acquired Anadarko’s then-remaining 24% membership interest in Chipeta, receiving distributions related to the additional interest effective July 1, 2012.
|
(5)
|
Acquired a 20% interest in each of TEG and TEP and a 33.33% interest in FRP.
|
thousands except per-unit data, throughput, Adjusted gross margin per Mcf and Adjusted gross margin per Bbl
|
Summary Financial Information
|
||||||||||||||||||
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|||||||||||
Statement of Operations Data (for the year ended):
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
$
|
1,804,270
|
|
|
$
|
1,752,072
|
|
|
$
|
1,533,377
|
|
|
$
|
1,200,060
|
|
|
$
|
998,031
|
|
Operating income (loss)
|
708,208
|
|
|
157,330
|
|
|
554,731
|
|
|
325,619
|
|
|
228,226
|
|
|||||
Net income (loss)
|
602,294
|
|
|
14,207
|
|
|
456,668
|
|
|
288,244
|
|
|
170,532
|
|
|||||
Net income attributable to noncontrolling interest
|
10,963
|
|
|
10,101
|
|
|
14,025
|
|
|
10,816
|
|
|
14,890
|
|
|||||
Net income (loss) attributable to Western Gas Partners, LP
|
591,331
|
|
|
4,106
|
|
|
442,643
|
|
|
277,428
|
|
|
155,642
|
|
|||||
Net income (loss) per common unit (basic)
|
1.74
|
|
|
(1.95
|
)
|
|
2.13
|
|
|
1.83
|
|
|
0.84
|
|
|||||
Net income (loss) per common unit (diluted)
|
1.74
|
|
|
(1.95
|
)
|
|
2.12
|
|
|
1.83
|
|
|
0.84
|
|
|||||
Distributions per unit
|
3.350
|
|
|
3.050
|
|
|
2.650
|
|
|
2.280
|
|
|
1.960
|
|
|||||
Balance Sheet Data (at year end):
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
$
|
7,733,028
|
|
|
$
|
7,301,197
|
|
|
$
|
7,549,785
|
|
|
$
|
5,328,224
|
|
|
$
|
4,472,834
|
|
Total long-term liabilities
|
3,281,944
|
|
|
3,147,681
|
|
|
2,699,244
|
|
|
1,659,229
|
|
|
1,373,766
|
|
|||||
Total equity and partners’ capital
|
4,135,779
|
|
|
3,918,028
|
|
|
4,568,462
|
|
|
3,422,675
|
|
|
2,865,352
|
|
|||||
Cash Flow Data (for the year ended):
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash flows provided by (used in):
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
$
|
917,585
|
|
|
$
|
785,645
|
|
|
$
|
694,495
|
|
|
$
|
601,335
|
|
|
$
|
409,448
|
|
Investing activities
|
(1,105,534
|
)
|
|
(500,277
|
)
|
|
(2,740,175
|
)
|
|
(1,858,912
|
)
|
|
(1,633,408
|
)
|
|||||
Financing activities
|
447,841
|
|
|
(254,389
|
)
|
|
2,011,970
|
|
|
938,324
|
|
|
1,417,380
|
|
|||||
Capital expenditures
|
(473,858
|
)
|
|
(637,503
|
)
|
|
(804,822
|
)
|
|
(851,771
|
)
|
|
(913,834
|
)
|
|||||
Throughput (MMcf/d except throughput measured in barrels):
|
|||||||||||||||||||
Total throughput for natural gas assets
|
4,064
|
|
|
4,300
|
|
|
3,984
|
|
|
3,611
|
|
|
3,211
|
|
|||||
Throughput attributable to noncontrolling interest for natural gas assets
|
124
|
|
|
142
|
|
|
165
|
|
|
168
|
|
|
228
|
|
|||||
Total throughput attributable to Western Gas Partners, LP for natural gas assets
|
3,940
|
|
|
4,158
|
|
|
3,819
|
|
|
3,443
|
|
|
2,983
|
|
|||||
Throughput for crude/NGL assets (MBbls/d)
|
184
|
|
|
186
|
|
|
154
|
|
|
62
|
|
|
44
|
|
|||||
Key Performance Metrics (for the year ended):
(1)
|
|
|
|
|
|
|
|
|
|
||||||||||
Adjusted gross margin attributable to
Western Gas Partners, LP for natural gas assets
|
$
|
1,194,877
|
|
|
$
|
1,119,555
|
|
|
$
|
993,397
|
|
|
$
|
775,040
|
|
|
$
|
615,177
|
|
Adjusted gross margin for crude/NGL assets
|
142,566
|
|
|
131,492
|
|
|
103,102
|
|
|
31,664
|
|
|
20,776
|
|
|||||
Adjusted gross margin per Mcf attributable to
Western Gas Partners, LP for natural gas assets
|
0.83
|
|
|
0.74
|
|
|
0.71
|
|
|
0.62
|
|
|
0.56
|
|
|||||
Adjusted gross margin per Bbl for crude/NGL assets
|
2.11
|
|
|
1.93
|
|
|
1.84
|
|
|
1.40
|
|
|
1.29
|
|
|||||
Adjusted EBITDA attributable to
Western Gas Partners, LP
|
1,028,208
|
|
|
907,568
|
|
|
782,900
|
|
|
539,401
|
|
|
428,986
|
|
|||||
Distributable cash flow
|
852,446
|
|
|
781,383
|
|
|
661,133
|
|
|
455,238
|
|
|
355,559
|
|
(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 the caption
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
|
|
11
|
|
|
4
|
|
|
5
|
|
|
2
|
|
Treating facilities
|
|
12
|
|
|
12
|
|
|
—
|
|
|
3
|
|
Natural gas processing plants/trains
|
|
20
|
|
|
5
|
|
|
—
|
|
|
2
|
|
NGL pipelines
|
|
2
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Natural gas pipelines
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Oil pipelines
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
•
|
We completed the acquisition of Springfield from Anadarko for cash and common unit consideration totaling $750.0 million. See
Acquisitions and Divestitures
under Part I, Items 1 and 2 of this Form 10-K for additional information.
|
•
|
We issued
21,922,831
Series A Preferred units to private investors, generating net proceeds of
$686.9 million
, a portion of which was used to fund the acquisition of Springfield. See
Equity Offerings
under Part I, Items 1 and 2 of this Form 10-K for additional information.
|
•
|
We completed the offering of $500.0 million aggregate principal amount of 2026 Notes in July 2016 and an offering of an additional $200.0 million in aggregate principal amount of 2044 Notes in October 2016. Net proceeds were used to repay amounts then outstanding under our RCF and for general partnership purposes, including capital expenditures. See
Liquidity and Capital Resources
within this
Item 7
for additional information.
|
•
|
We commenced operation of Trains IV and V at the DBM complex in May 2016 and October 2016, respectively. Both are 200 MMcf/d processing plants. Further, after sustaining damage during the December 3, 2015, incident at the DBM complex, Train II (with capacity of 100 MMcf/d) returned to service in December 2016 and Train III (with capacity of 200 MMcf/d) returned to service in May 2016.
|
•
|
We received
$33.8 million
in cash proceeds from insurers related to the incident at the DBM complex, including
$16.3 million
for business interruption insurance claims and
$17.5 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
$0.860
per unit for the
fourth
quarter of
2016
, representing a
2%
increase
over the distribution for the
third
quarter of 2016 and an
8%
increase
over the distribution for the
fourth
quarter of
2015
.
|
•
|
Throughput attributable to Western Gas Partners, LP for natural gas assets totaled
3,940
MMcf/d for the
year ended December 31, 2016
, representing a
5%
decrease
compared to the year ended December 31,
2015
.
|
•
|
Throughput for crude/NGL assets totaled
184
MBbls/d for the
year ended December 31, 2016
, representing a
1%
decrease
compared to the year ended December 31,
2015
.
|
•
|
Operating income (loss) was
$708.2 million
for the
year ended December 31, 2016
, representing a
350%
increase
compared to the year ended December 31,
2015
.
|
•
|
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (as defined under the caption
How We Evaluate Our Operations
within this
Item 7
) averaged
$0.83
per Mcf for the
year ended December 31, 2016
, representing a
12%
increase
compared to the year ended December 31,
2015
.
|
•
|
Adjusted gross margin for crude/NGL assets (as defined under the caption
How We Evaluate Our Operations
within this
Item 7
) averaged
$2.11
per Bbl for the
year ended December 31, 2016
, representing a
9%
increase
compared to the year ended December 31,
2015
.
|
•
|
expenses associated with annual and quarterly reporting;
|
•
|
tax return and Schedule K-1 preparation and distribution expenses;
|
•
|
expenses associated with listing on the NYSE; and
|
•
|
independent auditor fees, legal expenses, investor relations expenses, director fees, and registrar and transfer agent fees.
|
•
|
our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;
|
•
|
the ability of our assets to generate cash flow to make distributions; and
|
•
|
the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2016
|
|
2015
|
|
2014
|
||||||
Reconciliation of Operating income (loss) to Adjusted gross margin attributable to Western Gas Partners, LP
|
|
|
|
|
|
|
||||||
Operating income (loss)
|
|
$
|
708,208
|
|
|
$
|
157,330
|
|
|
$
|
554,731
|
|
Add:
|
|
|
|
|
|
|
||||||
Distributions from equity investments
|
|
103,423
|
|
|
98,298
|
|
|
81,022
|
|
|||
Operation and maintenance
|
|
308,010
|
|
|
331,972
|
|
|
293,710
|
|
|||
General and administrative
|
|
45,591
|
|
|
41,319
|
|
|
38,561
|
|
|||
Property and other taxes
|
|
40,145
|
|
|
33,288
|
|
|
28,889
|
|
|||
Depreciation and amortization
|
|
272,933
|
|
|
272,611
|
|
|
211,809
|
|
|||
Impairments
|
|
15,535
|
|
|
515,458
|
|
|
5,125
|
|
|||
Less:
|
|
|
|
|
|
|
||||||
Gain (loss) on divestiture and other, net
|
|
(14,641
|
)
|
|
57,024
|
|
|
(9
|
)
|
|||
Proceeds from business interruption insurance claims
|
|
16,270
|
|
|
—
|
|
|
—
|
|
|||
Equity income, net – affiliates
|
|
78,717
|
|
|
71,251
|
|
|
57,836
|
|
|||
Reimbursed electricity-related charges recorded as revenues
|
|
59,733
|
|
|
54,175
|
|
|
39,338
|
|
|||
Adjusted gross margin attributable to noncontrolling interest
|
|
16,323
|
|
|
16,779
|
|
|
20,183
|
|
|||
Adjusted gross margin attributable to Western Gas Partners, LP
|
|
$
|
1,337,443
|
|
|
$
|
1,251,047
|
|
|
$
|
1,096,499
|
|
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets
|
|
$
|
1,194,877
|
|
|
$
|
1,119,555
|
|
|
$
|
993,397
|
|
Adjusted gross margin for crude/NGL assets
|
|
142,566
|
|
|
131,492
|
|
|
103,102
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2016
|
|
2015
|
|
2014
|
||||||
Reconciliation of Net income (loss) attributable to Western Gas Partners, LP to Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
|
|
|
|
|
||||||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
591,331
|
|
|
$
|
4,106
|
|
|
$
|
442,643
|
|
Add:
|
|
|
|
|
|
|
||||||
Distributions from equity investments
|
|
103,423
|
|
|
98,298
|
|
|
81,022
|
|
|||
Non-cash equity-based compensation expense
|
|
5,591
|
|
|
4,402
|
|
|
4,095
|
|
|||
Interest expense
|
|
114,921
|
|
|
113,872
|
|
|
76,766
|
|
|||
Income tax expense
|
|
8,372
|
|
|
45,532
|
|
|
39,061
|
|
|||
Depreciation and amortization
(1)
|
|
270,311
|
|
|
270,004
|
|
|
209,240
|
|
|||
Impairments
|
|
15,535
|
|
|
515,458
|
|
|
5,125
|
|
|||
Other expense
(1)
|
|
224
|
|
|
1,290
|
|
|
—
|
|
|||
Less:
|
|
|
|
|
|
|
||||||
Gain (loss) on divestiture and other, net
|
|
(14,641
|
)
|
|
57,024
|
|
|
(9
|
)
|
|||
Equity income, net – affiliates
|
|
78,717
|
|
|
71,251
|
|
|
57,836
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Other income
(1) (2)
|
|
524
|
|
|
219
|
|
|
325
|
|
|||
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
$
|
1,028,208
|
|
|
$
|
907,568
|
|
|
$
|
782,900
|
|
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
|
$
|
917,585
|
|
|
$
|
785,645
|
|
|
$
|
694,495
|
|
Interest (income) expense, net
|
|
98,021
|
|
|
96,972
|
|
|
59,866
|
|
|||
Uncontributed cash-based compensation awards
|
|
856
|
|
|
214
|
|
|
175
|
|
|||
Accretion and amortization of long-term obligations, net
|
|
3,789
|
|
|
(17,698
|
)
|
|
(2,736
|
)
|
|||
Current income tax (benefit) expense
|
|
5,817
|
|
|
34,186
|
|
|
379
|
|
|||
Other (income) expense, net
(2)
|
|
(479
|
)
|
|
619
|
|
|
(336
|
)
|
|||
Distributions from equity investments in excess of cumulative earnings – affiliates
|
|
21,238
|
|
|
16,244
|
|
|
18,055
|
|
|||
Changes in operating working capital:
|
|
|
|
|
|
|
||||||
Accounts receivable, net
|
|
48,947
|
|
|
4,371
|
|
|
(1,399
|
)
|
|||
Accounts and imbalance payables and accrued liabilities, net
|
|
(58,359
|
)
|
|
(1,006
|
)
|
|
34,980
|
|
|||
Other
|
|
4,367
|
|
|
720
|
|
|
(3,996
|
)
|
|||
Adjusted EBITDA attributable to noncontrolling interest
|
|
(13,574
|
)
|
|
(12,699
|
)
|
|
(16,583
|
)
|
|||
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
$
|
1,028,208
|
|
|
$
|
907,568
|
|
|
$
|
782,900
|
|
Cash flow information of Western Gas Partners, LP
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
|
$
|
917,585
|
|
|
$
|
785,645
|
|
|
$
|
694,495
|
|
Net cash used in investing activities
|
|
(1,105,534
|
)
|
|
(500,277
|
)
|
|
(2,740,175
|
)
|
|||
Net cash provided by (used in) financing activities
|
|
447,841
|
|
|
(254,389
|
)
|
|
2,011,970
|
|
(1)
|
Includes our 75% share of depreciation and amortization; other expense; and other income attributable to the Chipeta complex. Other expense also includes
$0.2 million
and
$0.4 million
of lower of cost or market inventory adjustments at our DBM complex for the
years ended December 31, 2016
and
2015
, respectively.
|
(2)
|
Excludes income of $0.5 million for the year ended December 31, 2014, related to a component of a gas processing agreement accounted for as a capital lease.
|
|
|
Year Ended December 31,
|
||||||||||
thousands except Coverage ratio
|
|
2016
|
|
2015
|
|
2014
|
||||||
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
|
|
$
|
591,331
|
|
|
$
|
4,106
|
|
|
$
|
442,643
|
|
Add:
|
|
|
|
|
|
|
||||||
Distributions from equity investments
|
|
103,423
|
|
|
98,298
|
|
|
81,022
|
|
|||
Non-cash equity-based compensation expense
|
|
5,591
|
|
|
4,402
|
|
|
4,095
|
|
|||
Non-cash settled - interest expense, net
(1)
|
|
(7,747
|
)
|
|
14,400
|
|
|
—
|
|
|||
Income tax (benefit) expense
|
|
8,372
|
|
|
45,532
|
|
|
39,061
|
|
|||
Depreciation and amortization
(2)
|
|
270,311
|
|
|
270,004
|
|
|
209,240
|
|
|||
Impairments
|
|
15,535
|
|
|
515,458
|
|
|
5,125
|
|
|||
Above-market component of swap extensions with Anadarko
(3)
|
|
45,820
|
|
|
18,449
|
|
|
—
|
|
|||
Other expense
(2)
|
|
224
|
|
|
1,290
|
|
|
—
|
|
|||
Less:
|
|
|
|
|
|
|
||||||
Gain (loss) on divestiture and other, net
|
|
(14,641
|
)
|
|
57,024
|
|
|
(9
|
)
|
|||
Equity income, net – affiliates
|
|
78,717
|
|
|
71,251
|
|
|
57,836
|
|
|||
Cash paid for maintenance capital expenditures
(2)
|
|
63,630
|
|
|
53,882
|
|
|
52,159
|
|
|||
Capitalized interest
|
|
5,562
|
|
|
8,318
|
|
|
9,832
|
|
|||
Cash paid for (reimbursement of) income taxes
|
|
838
|
|
|
(138
|
)
|
|
(90
|
)
|
|||
Series A Preferred unit distributions
|
|
45,784
|
|
|
—
|
|
|
—
|
|
|||
Other income
(2) (4)
|
|
524
|
|
|
219
|
|
|
325
|
|
|||
Distributable cash flow
|
|
$
|
852,446
|
|
|
$
|
781,383
|
|
|
$
|
661,133
|
|
Distributions declared
(5)
|
|
|
|
|
|
|
||||||
Limited partners – common units
|
|
$
|
437,747
|
|
|
|
|
|
||||
General partner
|
|
221,384
|
|
|
|
|
|
|||||
Total
|
|
$
|
659,131
|
|
|
|
|
|
||||
Coverage ratio
|
|
1.29
|
|
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
$0.2 million
and
$0.4 million
of lower of cost or market inventory adjustments at our DBM complex for the
years ended December 31, 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)
|
Excludes income of $0.5 million for the year ended December 31, 2014, related to a component of a gas processing agreement accounted for as a capital lease.
|
(5)
|
Reflects cash distributions of
$3.350
per unit declared for the
year ended December 31, 2016
.
|
•
|
DBM acquisition.
In November 2014, we acquired Nuevo from a third party. Following the acquisition, we changed the name of Nuevo to Delaware Basin Midstream, LLC. We financed the acquisition with the issuance of $750.0 million of Class C units to a subsidiary of Anadarko, borrowings under our RCF and cash on hand, including the proceeds from the November 2014 equity offering. These assets have been recorded in our consolidated financial statements at their estimated fair values on the acquisition date under the acquisition method of accounting. Results of operations attributable to the DBM acquisition were included in our consolidated statement of operations beginning on the acquisition date in the fourth quarter of 2014.
|
•
|
DBJV acquisition.
In March 2015, we acquired Anadarko’s interest in DBJV. We will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. As of the acquisition date, we estimated the future payment to be
$282.8 million
, the net present value of which was
$174.3 million
. As of
December 31, 2016
, the net present value of this obligation was
$41.4 million
and has been recorded on the consolidated balance sheet under Deferred purchase price obligation - Anadarko. Accretion revision was
$7.7 million
for the year ended
December 31, 2016
, and accretion expense was $14.4 million and zero for the years ended
December 31, 2015
and
2014
, respectively.
|
•
|
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.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2016
|
|
2015
|
|
2014
|
||||||
Total revenues and other
(1)
|
|
$
|
1,804,270
|
|
|
$
|
1,752,072
|
|
|
$
|
1,533,377
|
|
Equity income, net – affiliates
|
|
78,717
|
|
|
71,251
|
|
|
57,836
|
|
|||
Total operating expenses
(1)
|
|
1,176,408
|
|
|
1,723,017
|
|
|
1,036,473
|
|
|||
Gain (loss) on divestiture and other, net
|
|
(14,641
|
)
|
|
57,024
|
|
|
(9
|
)
|
|||
Proceeds from business interruption insurance claims
(2)
|
|
16,270
|
|
|
—
|
|
|
—
|
|
|||
Operating income (loss)
|
|
708,208
|
|
|
157,330
|
|
|
554,731
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
|
|
(114,921
|
)
|
|
(113,872
|
)
|
|
(76,766
|
)
|
|||
Other income (expense), net
|
|
479
|
|
|
(619
|
)
|
|
864
|
|
|||
Income (loss) before income taxes
|
|
610,666
|
|
|
59,739
|
|
|
495,729
|
|
|||
Income tax (benefit) expense
|
|
8,372
|
|
|
45,532
|
|
|
39,061
|
|
|||
Net income (loss)
|
|
602,294
|
|
|
14,207
|
|
|
456,668
|
|
|||
Net income attributable to noncontrolling interest
|
|
10,963
|
|
|
10,101
|
|
|
14,025
|
|
|||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
591,331
|
|
|
$
|
4,106
|
|
|
$
|
442,643
|
|
Key performance metrics
(3)
|
|
|
|
|
|
|
||||||
Adjusted gross margin attributable to Western Gas Partners, LP
|
|
$
|
1,337,443
|
|
|
$
|
1,251,047
|
|
|
$
|
1,096,499
|
|
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
1,028,208
|
|
|
907,568
|
|
|
782,900
|
|
|||
Distributable cash flow
|
|
852,446
|
|
|
781,383
|
|
|
661,133
|
|
(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 attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow are defined under the caption
Key Performance Metrics
within this
Item 7
.
For reconciliations of Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see
How We Evaluate Our Operations–Reconciliation to non-GAAP Measures
within this
Item 7
.
|
|
|
Year Ended December 31,
|
|||||||||||||
|
|
2016
|
|
2015
|
|
Inc/
(Dec)
|
|
2014
|
|
Inc/
(Dec) |
|||||
Throughput for natural gas assets (MMcf/d)
|
|
|
|
|
|
|
|
|
|
|
|||||
Gathering, treating and transportation
|
|
1,537
|
|
|
1,791
|
|
|
(14
|
)%
|
|
1,888
|
|
|
(5
|
)%
|
Processing
|
|
2,350
|
|
|
2,331
|
|
|
1
|
%
|
|
1,925
|
|
|
21
|
%
|
Equity investment
(1)
|
|
177
|
|
|
178
|
|
|
(1
|
)%
|
|
171
|
|
|
4
|
%
|
Total throughput for natural gas assets
|
|
4,064
|
|
|
4,300
|
|
|
(5
|
)%
|
|
3,984
|
|
|
8
|
%
|
Throughput attributable to noncontrolling interest for natural gas assets
|
|
124
|
|
|
142
|
|
|
(13
|
)%
|
|
165
|
|
|
(14
|
)%
|
Total throughput attributable to Western Gas Partners, LP for natural gas assets
|
|
3,940
|
|
|
4,158
|
|
|
(5
|
)%
|
|
3,819
|
|
|
9
|
%
|
Throughput for crude/NGL assets (MBbls/d)
|
|
|
|
|
|
|
|
|
|
|
|||||
Gathering, treating and transportation
|
|
57
|
|
|
69
|
|
|
(17
|
)%
|
|
64
|
|
|
8
|
%
|
Equity investment
(2)
|
|
127
|
|
|
117
|
|
|
9
|
%
|
|
90
|
|
|
30
|
%
|
Total throughput for crude/NGL assets
|
|
184
|
|
|
186
|
|
|
(1
|
)%
|
|
154
|
|
|
21
|
%
|
(1)
|
Represents our 14.81% share of average Fort Union throughput and our 22% share of average Rendezvous throughput.
|
(2)
|
Represents our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput, and our 33.33% share of average FRP throughput.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2016
|
|
2015
|
|
Inc/
(Dec)
|
|
2014
|
|
Inc/
(Dec)
|
||||||||
Gathering, processing and transportation revenues
|
|
$
|
1,227,849
|
|
|
$
|
1,128,838
|
|
|
9
|
%
|
|
$
|
894,034
|
|
|
26
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages and per-unit amounts
|
|
2016
|
|
2015
|
|
Inc/
(Dec)
|
|
2014
|
|
Inc/
(Dec)
|
||||||||
Natural gas sales
(1)
|
|
$
|
230,366
|
|
|
$
|
242,826
|
|
|
(5
|
)%
|
|
$
|
167,814
|
|
|
45
|
%
|
Natural gas liquids sales
(1)
|
|
341,947
|
|
|
375,123
|
|
|
(9
|
)%
|
|
458,091
|
|
|
(18
|
)%
|
|||
Total
|
|
$
|
572,313
|
|
|
$
|
617,949
|
|
|
(7
|
)%
|
|
$
|
625,905
|
|
|
(1
|
)%
|
Average price per unit
(1)
:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas (per Mcf)
|
|
$
|
2.51
|
|
|
$
|
3.28
|
|
|
(23
|
)%
|
|
$
|
4.16
|
|
|
(21
|
)%
|
Natural gas liquids (per Bbl)
|
|
19.96
|
|
|
22.38
|
|
|
(11
|
)%
|
|
43.58
|
|
|
(49
|
)%
|
(1)
|
Excludes amounts considered above market, with respect to our swap extensions at the DJ Basin complex and the Hugoton system beginning July 1, 2015, that are 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
|
|
2016
|
|
2015
|
|
Inc/
(Dec)
|
|
2014
|
|
Inc/
(Dec)
|
||||||||
Equity income, net – affiliates
|
|
$
|
78,717
|
|
|
$
|
71,251
|
|
|
10
|
%
|
|
$
|
57,836
|
|
|
23
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2016
|
|
2015
|
|
Inc/
(Dec)
|
|
2014
|
|
Inc/
(Dec)
|
||||||||
NGL purchases
(1)
|
|
$
|
238,660
|
|
|
$
|
251,222
|
|
|
(5
|
)%
|
|
$
|
232,889
|
|
|
8
|
%
|
Residue purchases
(1)
|
|
231,722
|
|
|
253,619
|
|
|
(9
|
)%
|
|
186,341
|
|
|
36
|
%
|
|||
Other
(1)
|
|
23,812
|
|
|
23,528
|
|
|
1
|
%
|
|
39,149
|
|
|
(40
|
)%
|
|||
Cost of product
|
|
494,194
|
|
|
528,369
|
|
|
(6
|
)%
|
|
458,379
|
|
|
15
|
%
|
|||
Operation and maintenance
|
|
308,010
|
|
|
331,972
|
|
|
(7
|
)%
|
|
293,710
|
|
|
13
|
%
|
|||
Total cost of product and operation and maintenance expenses
|
|
$
|
802,204
|
|
|
$
|
860,341
|
|
|
(7
|
)%
|
|
$
|
752,089
|
|
|
14
|
%
|
(1)
|
Excludes amounts considered above market, with respect to our swap extensions at the DJ Basin complex and the Hugoton system beginning July 1, 2015, that are 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
|
|
2016
|
|
2015
|
|
Inc/
(Dec)
|
|
2014
|
|
Inc/
(Dec)
|
||||||||
General and administrative
|
|
$
|
45,591
|
|
|
$
|
41,319
|
|
|
10
|
%
|
|
$
|
38,561
|
|
|
7
|
%
|
Property and other taxes
|
|
40,145
|
|
|
33,288
|
|
|
21
|
%
|
|
28,889
|
|
|
15
|
%
|
|||
Depreciation and amortization
|
|
272,933
|
|
|
272,611
|
|
|
—
|
%
|
|
211,809
|
|
|
29
|
%
|
|||
Impairments
|
|
15,535
|
|
|
515,458
|
|
|
(97
|
)%
|
|
5,125
|
|
|
NM
|
|
|||
Total other operating expenses
|
|
$
|
374,204
|
|
|
$
|
862,676
|
|
|
(57
|
)%
|
|
$
|
284,384
|
|
|
NM
|
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2016
|
|
2015
|
|
Inc/
(Dec)
|
|
2014
|
|
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
|
|
$
|
(121,832
|
)
|
|
$
|
(102,058
|
)
|
|
19
|
%
|
|
$
|
(81,495
|
)
|
|
25
|
%
|
Amortization of debt issuance costs and commitment fees
|
|
(6,398
|
)
|
|
(5,734
|
)
|
|
12
|
%
|
|
(5,103
|
)
|
|
12
|
%
|
|||
Capitalized interest
|
|
5,562
|
|
|
8,318
|
|
|
(33
|
)%
|
|
9,832
|
|
|
(15
|
)%
|
|||
Affiliates
|
|
|
|
|
|
|
|
|
|
|
||||||||
Deferred purchase price obligation – Anadarko
(1)
|
|
7,747
|
|
|
(14,398
|
)
|
|
(154
|
)%
|
|
—
|
|
|
—
|
%
|
|||
Interest expense
|
|
$
|
(114,921
|
)
|
|
$
|
(113,872
|
)
|
|
1
|
%
|
|
$
|
(76,766
|
)
|
|
48
|
%
|
(1)
|
See
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under
Part II
,
Item 8
of this Form
10-K
for a discussion of the Deferred purchase price obligation - Anadarko.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2016
|
|
2015
|
|
Inc/
(Dec)
|
|
2014
|
|
Inc/
(Dec)
|
||||||||
Income (loss) before income taxes
|
|
$
|
610,666
|
|
|
$
|
59,739
|
|
|
NM
|
|
|
$
|
495,729
|
|
|
(88
|
)%
|
Income tax (benefit) expense
|
|
8,372
|
|
|
45,532
|
|
|
(82
|
)%
|
|
39,061
|
|
|
17
|
%
|
|||
Effective tax rate
|
|
1
|
%
|
|
76
|
%
|
|
|
|
8
|
%
|
|
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages and per-unit amounts
|
|
2016
|
|
2015
|
|
Inc/
(Dec)
|
|
2014
|
|
Inc/
(Dec)
|
||||||||
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets
(1)
|
|
$
|
1,194,877
|
|
|
$
|
1,119,555
|
|
|
7
|
%
|
|
$
|
993,397
|
|
|
13
|
%
|
Adjusted gross margin for crude/NGL assets
(2)
|
|
142,566
|
|
|
131,492
|
|
|
8
|
%
|
|
103,102
|
|
|
28
|
%
|
|||
Adjusted gross margin attributable to Western Gas Partners, LP
(3)
|
|
1,337,443
|
|
|
1,251,047
|
|
|
7
|
%
|
|
1,096,499
|
|
|
14
|
%
|
|||
Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets
(4)
|
|
0.83
|
|
|
0.74
|
|
|
12
|
%
|
|
0.71
|
|
|
4
|
%
|
|||
Adjusted gross margin per Bbl for crude/NGL assets
(5)
|
|
2.11
|
|
|
1.93
|
|
|
9
|
%
|
|
1.84
|
|
|
5
|
%
|
|||
Adjusted EBITDA attributable to Western Gas Partners, LP
(3)
|
|
1,028,208
|
|
|
907,568
|
|
|
13
|
%
|
|
782,900
|
|
|
16
|
%
|
|||
Distributable cash flow
(3)
|
|
852,446
|
|
|
781,383
|
|
|
9
|
%
|
|
661,133
|
|
|
18
|
%
|
(1)
|
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets is calculated as total revenues and other for natural gas assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for natural gas assets, plus distributions from our equity investments in Fort Union and Rendezvous, and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. See the reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets to its most comparable GAAP measure under
How We Evaluate Our Operations—Reconciliation to GAAP measures
within this Item 7.
|
(2)
|
Adjusted gross margin for crude/NGL assets is calculated as total revenues and other for crude/NGL assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for crude/NGL assets, plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, and the TEFR Interests. See the reconciliation of Adjusted gross margin for crude/NGL assets to its most comparable GAAP measure under
How We Evaluate Our Operations—Reconciliation to GAAP measures
within this Item 7.
|
(3)
|
For a reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow to the most directly comparable financial measure calculated and presented in accordance with GAAP, see
How We Evaluate Our Operations—Reconciliation to GAAP measures
within this Item 7.
|
(4)
|
Average for period. Calculated as Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets, divided by total throughput (MMcf/d) attributable to Western Gas Partners, LP for natural gas assets.
|
(5)
|
Average for period. Calculated as Adjusted gross margin for crude/NGL assets, divided by total throughput (MBbls/d) for crude/NGL assets.
|
•
|
maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, such as to replace system components and equipment that have been subject to significant use over time, become obsolete or reached the end of their useful lives, to remain in compliance with regulatory or legal requirements or to complete additional well connections to maintain existing system throughput and related cash flows; or
|
•
|
expansion capital expenditures, which include expenditures to construct new midstream infrastructure and those expenditures incurred to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system throughput.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2016
|
|
2015
|
|
2014
|
||||||
Acquisitions
|
|
$
|
716,465
|
|
|
$
|
14,417
|
|
|
$
|
1,902,520
|
|
|
|
|
|
|
|
|
||||||
Expansion capital expenditures
|
|
$
|
410,221
|
|
|
$
|
583,282
|
|
|
$
|
752,207
|
|
Maintenance capital expenditures
|
|
63,637
|
|
|
54,221
|
|
|
52,615
|
|
|||
Total capital expenditures
(1) (2)
|
|
$
|
473,858
|
|
|
$
|
637,503
|
|
|
$
|
804,822
|
|
|
|
|
|
|
|
|
||||||
Capital incurred
(2)
|
|
$
|
491,349
|
|
|
$
|
566,045
|
|
|
$
|
833,872
|
|
(1)
|
Capital expenditures for the years ended December 31,
2016
,
2015
and
2014
, are presented net of
$6.1 million
,
$0.5 million
and
$0.2 million
, respectively, of contributions in aid of construction costs from affiliates.
|
(2)
|
Includes the noncontrolling interest owner’s share of Chipeta’s capital expenditures for all periods presented. For the years ended December 31,
2016
,
2015
and
2014
, included
$5.6 million
,
$8.3 million
and
$9.8 million
, respectively, of capitalized interest.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2016
|
|
2015
|
|
2014
|
||||||
Net cash provided by (used in):
|
|
|
|
|
|
|
||||||
Operating activities
|
|
$
|
917,585
|
|
|
$
|
785,645
|
|
|
$
|
694,495
|
|
Investing activities
|
|
(1,105,534
|
)
|
|
(500,277
|
)
|
|
(2,740,175
|
)
|
|||
Financing activities
|
|
447,841
|
|
|
(254,389
|
)
|
|
2,011,970
|
|
|||
Net increase (decrease) in cash and cash equivalents
|
|
$
|
259,892
|
|
|
$
|
30,979
|
|
|
$
|
(33,710
|
)
|
•
|
$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;
|
•
|
$4.0 million
of cash paid for equipment purchases from Anadarko;
|
•
|
$21.2 million
of distributions from equity investments in excess of cumulative earnings; and
|
•
|
$17.5 million
of proceeds from property insurance claims attributable to the DBM outage.
|
•
|
$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;
|
•
|
$10.9 million
of cash paid for equipment purchases from Anadarko;
|
•
|
$11.4 million
of cash contributed to equity investments, primarily related to expansion projects at White Cliffs, TEP and FRP;
|
•
|
$3.5 million
of cash paid for post-closing purchase price adjustments related to the DBM acquisition;
|
•
|
$145.6 million of net proceeds from the sale of the Dew and Pinnacle systems in East Texas; and
|
•
|
$16.2 million
of distributions from equity investments in excess of cumulative earnings.
|
•
|
$1.5 billion
of cash paid for the acquisition of DBM, net of $30.6 million of cash acquired;
|
•
|
$804.8 million
of capital expenditures, net of
$0.2 million
of contributions in aid of construction costs from affiliates, primarily related to the construction of Lancaster Trains I and II, as well as compression expansion projects, all within the DJ Basin complex;
|
•
|
$356.3 million of cash paid for the acquisition of the TEFR Interests;
|
•
|
$42.0 million of cash paid related to the construction of the Front Range Pipeline, which was completed in March 2014;
|
•
|
$22.9 million
of cash paid for equipment purchases from Anadarko;
|
•
|
$10.5 million of cash paid for White Cliffs expansion projects;
|
•
|
$6.6 million of cash paid related to the construction of the Texas Express Pipeline, which was completed in November 2013;
|
•
|
$18.1 million
of distributions from equity investments in excess of cumulative earnings; and
|
•
|
$13.0 million
of net proceeds, after closing adjustments, from the sale of a gathering system to a third party in September 2014.
|
•
|
$599.3 million of borrowings under our 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 our RCF;
|
•
|
$440.0 million of net proceeds from the March 2016 Series A units issuance, all of which was used to fund a portion of the acquisition of Springfield;
|
•
|
$246.9 million
of net proceeds from the April 2016 Series A units issuance, all of which was used to pay down amounts borrowed under our RCF in connection with the Springfield acquisition;
|
•
|
$203.3 million of net proceeds from the offering of 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 our RCF and for general partnership purposes, including capital expenditures;
|
•
|
$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;
|
•
|
$45.8 million
of capital contribution from Anadarko related to the above-market component of swap extensions;
|
•
|
$900.0 million of repayments of outstanding borrowing under our RCF;
|
•
|
$671.9 million
of distributions paid to our unitholders;
|
•
|
$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 our RCF;
|
•
|
$545.1 million
of distributions paid to our unitholders;
|
•
|
$49.8 million
of net distributions paid to Anadarko representing pre-acquisition intercompany transactions attributable to Springfield and DBJV;
|
•
|
$12.2 million
of distributions paid to the noncontrolling interest owner of Chipeta;
|
•
|
$489.6 million of net proceeds from the 2025 Notes offering in June 2015, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of the outstanding borrowings under our RCF;
|
•
|
$400.0 million of borrowings under our 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 $500.0 million COP (as discussed in
Securities
within this
Item 7
). Net proceeds were used for general partnership purposes, including funding capital expenditures; and
|
•
|
$18.4 million
of capital contribution from Anadarko related to the above-market component of swap extensions.
|
•
|
$750.0 million
of proceeds from the issuance of Class C units to a subsidiary of Anadarko, all of which was used to fund a portion of the acquisition of DBM;
|
•
|
$603.0 million of net proceeds from the November 2014 equity offering, including net proceeds from a capital contribution by our general partner, part of which was used to fund a portion of the acquisition of DBM;
|
•
|
$475.0 million of borrowings to fund a portion of the acquisition of DBM;
|
•
|
$389.5 million of net proceeds from the 2044 Notes offering in March 2014, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of the outstanding borrowings under our RCF;
|
•
|
$350.0 million of borrowings to fund the acquisition of the TEFR Interests;
|
•
|
$335.0 million of borrowings to fund capital expenditures and general partnership purposes;
|
•
|
$100.0 million of net proceeds from the offering of additional 2018 Notes in March 2014, after underwriting discounts, original issue premium and offering costs, part of which was used to repay a portion of the outstanding borrowings under our RCF;
|
•
|
$83.2 million
of net proceeds from sales of common units under the $125.0 million COP, including net proceeds from capital contributions by our general partner;
|
•
|
$18.1 million of net proceeds related to the partial exercise of the underwriters’ over-allotment option granted in connection with our December 2013 equity offering;
|
•
|
$650.0 million
of repayments of outstanding borrowings under our RCF;
|
•
|
$408.6 million
of distributions paid to our unitholders;
|
•
|
$16.4 million
of net distributions to Anadarko representing intercompany transactions attributable to the acquisitions of Springfield, DBJV and the TEFR Interests; and
|
•
|
$15.1 million
of distributions paid to the noncontrolling interest owner of Chipeta.
|
|
|
Obligations by Period
|
||||||||||||||||||||||||||
thousands
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
||||||||||||||
Long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Principal
|
|
$
|
—
|
|
|
$
|
350,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
500,000
|
|
|
$
|
2,270,000
|
|
|
$
|
3,120,000
|
|
Interest
|
|
138,475
|
|
|
135,026
|
|
|
129,375
|
|
|
129,375
|
|
|
112,727
|
|
|
934,645
|
|
|
1,579,623
|
|
|||||||
Asset retirement obligations
|
|
3,114
|
|
|
—
|
|
|
395
|
|
|
—
|
|
|
1,564
|
|
|
137,334
|
|
|
142,407
|
|
|||||||
Capital expenditures
|
|
50,935
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
50,935
|
|
|||||||
Credit facility fees
|
|
2,400
|
|
|
2,400
|
|
|
2,400
|
|
|
375
|
|
|
—
|
|
|
—
|
|
|
7,575
|
|
|||||||
Environmental obligations
|
|
630
|
|
|
452
|
|
|
452
|
|
|
302
|
|
|
302
|
|
|
32
|
|
|
2,170
|
|
|||||||
Operating leases
|
|
7,322
|
|
|
898
|
|
|
764
|
|
|
122
|
|
|
—
|
|
|
—
|
|
|
9,106
|
|
|||||||
Deferred purchase price obligation - Anadarko
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56,455
|
|
|
—
|
|
|
—
|
|
|
56,455
|
|
|||||||
Total
|
|
$
|
202,876
|
|
|
$
|
488,776
|
|
|
$
|
133,386
|
|
|
$
|
186,629
|
|
|
$
|
614,593
|
|
|
$
|
3,342,011
|
|
|
$
|
4,968,271
|
|
•
|
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, Chief Executive Officer,
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
|
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues and other – affiliates
|
|
|
|
|
|
|
||||||
Gathering, processing and transportation
|
|
$
|
750,087
|
|
|
$
|
772,361
|
|
|
$
|
615,907
|
|
Natural gas and natural gas liquids sales
|
|
478,145
|
|
|
447,106
|
|
|
582,989
|
|
|||
Other
|
|
—
|
|
|
1,172
|
|
|
5,078
|
|
|||
Total revenues and other – affiliates
|
|
1,228,232
|
|
|
1,220,639
|
|
|
1,203,974
|
|
|||
Revenues and other – third parties
|
|
|
|
|
|
|
||||||
Gathering, processing and transportation
|
|
477,762
|
|
|
356,477
|
|
|
278,127
|
|
|||
Natural gas and natural gas liquids sales
|
|
94,168
|
|
|
170,843
|
|
|
42,916
|
|
|||
Other
|
|
4,108
|
|
|
4,113
|
|
|
8,360
|
|
|||
Total revenues and other – third parties
|
|
576,038
|
|
|
531,433
|
|
|
329,403
|
|
|||
Total revenues and other
|
|
1,804,270
|
|
|
1,752,072
|
|
|
1,533,377
|
|
|||
Equity income, net – affiliates
|
|
78,717
|
|
|
71,251
|
|
|
57,836
|
|
|||
Operating expenses
|
|
|
|
|
|
|
||||||
Cost of product
(1)
|
|
494,194
|
|
|
528,369
|
|
|
458,379
|
|
|||
Operation and maintenance
(1)
|
|
308,010
|
|
|
331,972
|
|
|
293,710
|
|
|||
General and administrative
(1)
|
|
45,591
|
|
|
41,319
|
|
|
38,561
|
|
|||
Property and other taxes
|
|
40,145
|
|
|
33,288
|
|
|
28,889
|
|
|||
Depreciation and amortization
|
|
272,933
|
|
|
272,611
|
|
|
211,809
|
|
|||
Impairments
|
|
15,535
|
|
|
515,458
|
|
|
5,125
|
|
|||
Total operating expenses
|
|
1,176,408
|
|
|
1,723,017
|
|
|
1,036,473
|
|
|||
Gain (loss) on divestiture and other, net
(2)
|
|
(14,641
|
)
|
|
57,024
|
|
|
(9
|
)
|
|||
Proceeds from business interruption insurance claims
|
|
16,270
|
|
|
—
|
|
|
—
|
|
|||
Operating income (loss)
|
|
708,208
|
|
|
157,330
|
|
|
554,731
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
(3)
|
|
(114,921
|
)
|
|
(113,872
|
)
|
|
(76,766
|
)
|
|||
Other income (expense), net
|
|
479
|
|
|
(619
|
)
|
|
864
|
|
|||
Income (loss) before income taxes
|
|
610,666
|
|
|
59,739
|
|
|
495,729
|
|
|||
Income tax (benefit) expense
|
|
8,372
|
|
|
45,532
|
|
|
39,061
|
|
|||
Net income (loss)
|
|
602,294
|
|
|
14,207
|
|
|
456,668
|
|
|||
Net income attributable to noncontrolling interest
|
|
10,963
|
|
|
10,101
|
|
|
14,025
|
|
|||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
591,331
|
|
|
$
|
4,106
|
|
|
$
|
442,643
|
|
Limited partners’ interest in net income (loss):
|
|
|
|
|
|
|
||||||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
591,331
|
|
|
$
|
4,106
|
|
|
$
|
442,643
|
|
Pre-acquisition net (income) loss allocated to Anadarko
|
|
(11,326
|
)
|
|
(79,386
|
)
|
|
(65,154
|
)
|
|||
Series A Preferred units interest in net (income) loss
(4)
|
|
(76,893
|
)
|
|
—
|
|
|
—
|
|
|||
General partner interest in net (income) loss
(4)
|
|
(236,561
|
)
|
|
(180,996
|
)
|
|
(120,980
|
)
|
|||
Common and Class C limited partners’ interest in net income (loss)
(4)
|
|
266,551
|
|
|
(256,276
|
)
|
|
256,509
|
|
|||
Net income (loss) per common unit – basic
(5)
|
|
$
|
1.74
|
|
|
$
|
(1.95
|
)
|
|
$
|
2.13
|
|
Net income (loss) per common unit – diluted
(5)
|
|
1.74
|
|
|
(1.95
|
)
|
|
2.12
|
|
(1)
|
Cost of product includes product purchases from Anadarko (as defined in
Note 1
) of
$80.5 million
,
$167.4 million
and
$127.9 million
for the
years ended December 31, 2016
,
2015
and
2014
, respectively. Operation and maintenance includes charges from Anadarko of
$72.3 million
,
$77.1 million
and
$71.4 million
for the
years ended December 31, 2016
,
2015
and
2014
, respectively. General and administrative includes charges from Anadarko of
$38.1 million
,
$33.9 million
and
$31.3 million
for the
years ended December 31, 2016
,
2015
and
2014
, respectively. See
Note 5
.
|
(2)
|
Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See
Note 1
.
|
(3)
|
Includes affiliate (as defined in
Note 1
) amounts of
$7.7 million
,
$(14.4) million
and
zero
for the
years ended December 31, 2016
,
2015
and
2014
, 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
|
|
2016
|
|
2015
|
||||
ASSETS
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
357,925
|
|
|
$
|
98,033
|
|
Accounts receivable, net
(1)
|
|
223,223
|
|
|
193,329
|
|
||
Other current assets
|
|
12,866
|
|
|
7,855
|
|
||
Total current assets
|
|
594,014
|
|
|
299,217
|
|
||
Note receivable – Anadarko
|
|
260,000
|
|
|
260,000
|
|
||
Property, plant and equipment
|
|
|
|
|
||||
Cost
|
|
6,861,942
|
|
|
6,556,778
|
|
||
Less accumulated depreciation
|
|
1,812,010
|
|
|
1,697,999
|
|
||
Net property, plant and equipment
|
|
5,049,932
|
|
|
4,858,779
|
|
||
Goodwill
|
|
417,610
|
|
|
419,186
|
|
||
Other intangible assets
|
|
803,698
|
|
|
832,127
|
|
||
Equity investments
|
|
594,208
|
|
|
618,887
|
|
||
Other assets
|
|
13,566
|
|
|
13,001
|
|
||
Total assets
|
|
$
|
7,733,028
|
|
|
$
|
7,301,197
|
|
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accounts and imbalance payables
|
|
$
|
123,285
|
|
|
$
|
98,661
|
|
Accrued ad valorem taxes
|
|
23,121
|
|
|
17,808
|
|
||
Accrued liabilities
|
|
168,899
|
|
|
119,019
|
|
||
Total current liabilities
|
|
315,305
|
|
|
235,488
|
|
||
Long-term debt
|
|
3,091,461
|
|
|
2,690,651
|
|
||
Deferred income taxes
|
|
6,402
|
|
|
139,704
|
|
||
Asset retirement obligations and other
|
|
142,641
|
|
|
128,652
|
|
||
Deferred purchase price obligation – Anadarko
(2)
|
|
41,440
|
|
|
188,674
|
|
||
Total long-term liabilities
|
|
3,281,944
|
|
|
3,147,681
|
|
||
Total liabilities
|
|
3,597,249
|
|
|
3,383,169
|
|
||
Equity and partners’ capital
|
|
|
|
|
||||
Series A Preferred units (21,922,831 and zero units issued and outstanding at December 31, 2016 and 2015, respectively)
(3)
|
|
639,545
|
|
|
—
|
|
||
Common units (130,671,970 and 128,576,965 units issued and outstanding at December 31, 2016 and 2015, respectively)
|
|
2,536,872
|
|
|
2,588,991
|
|
||
Class C units (12,358,123 and 11,411,862 units issued and outstanding at December 31, 2016 and 2015, respectively)
(4)
|
|
750,831
|
|
|
710,891
|
|
||
General partner units (2,583,068 units issued and outstanding at December 31, 2016 and 2015)
|
|
143,968
|
|
|
120,164
|
|
||
Net investment by Anadarko
|
|
—
|
|
|
430,598
|
|
||
Total partners’ capital
|
|
4,071,216
|
|
|
3,850,644
|
|
||
Noncontrolling interest
|
|
64,563
|
|
|
67,384
|
|
||
Total equity and partners’ capital
|
|
4,135,779
|
|
|
3,918,028
|
|
||
Total liabilities, equity and partners’ capital
|
|
$
|
7,733,028
|
|
|
$
|
7,301,197
|
|
(1)
|
Accounts receivable, net includes amounts receivable from affiliates (as defined in
Note 1
) of
$76.6 million
and
$42.7 million
as of
December 31, 2016
and 2015, respectively. Accounts receivable, net as of
December 31, 2016
and 2015, also includes an insurance claim receivable related to an incident at the DBM complex. See
Note 1
.
|
(2)
|
See
Note 2
.
|
(3)
|
The Series A Preferred units are convertible into common units at the holder’s election on a one-for-one basis at any time after the second anniversary of the issuance date. See
Note 4
.
|
(4)
|
The Class C units will convert into common units on a one-for-one basis on December 31, 2017, 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, 2013
|
|
$
|
842,731
|
|
|
$
|
2,431,193
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
78,157
|
|
|
$
|
70,594
|
|
|
$
|
3,422,675
|
|
Net income (loss)
|
|
65,154
|
|
|
254,737
|
|
|
1,772
|
|
|
—
|
|
|
120,980
|
|
|
14,025
|
|
|
456,668
|
|
|||||||
Issuance of common and general partner units, net of offering expenses
|
|
—
|
|
|
691,417
|
|
|
—
|
|
|
—
|
|
|
13,311
|
|
|
—
|
|
|
704,728
|
|
|||||||
Issuance of Class C units
|
|
—
|
|
|
—
|
|
|
750,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
750,000
|
|
|||||||
Beneficial conversion feature of Class C units
|
|
—
|
|
|
34,815
|
|
|
(34,815
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Distributions to noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15,149
|
)
|
|
(15,149
|
)
|
|||||||
Distributions to unitholders
|
|
—
|
|
|
(302,049
|
)
|
|
—
|
|
|
—
|
|
|
(106,572
|
)
|
|
—
|
|
|
(408,621
|
)
|
|||||||
Acquisitions from affiliates
|
|
(372,784
|
)
|
|
16,534
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(356,250
|
)
|
|||||||
Contributions of equity-based compensation from Anadarko
|
|
—
|
|
|
3,104
|
|
|
—
|
|
|
—
|
|
|
63
|
|
|
—
|
|
|
3,167
|
|
|||||||
Net pre-acquisition contributions from (distributions to) Anadarko
(1)
|
|
(16,692
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(16,692
|
)
|
|||||||
Net distributions to Anadarko of other assets
|
|
—
|
|
|
(10,492
|
)
|
|
—
|
|
|
—
|
|
|
(214
|
)
|
|
—
|
|
|
(10,706
|
)
|
|||||||
Elimination of net deferred tax liabilities
|
|
38,160
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
38,160
|
|
|||||||
Other
|
|
27
|
|
|
455
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
482
|
|
|||||||
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 extensions with Anadarko
(2)
|
|
—
|
|
|
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 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 extensions with Anadarko
(2)
|
|
—
|
|
|
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
(3)
|
|
—
|
|
|
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 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
|
|
(1)
|
Includes deferred taxes on capitalized interest of
$0.3 million
associated with the acquisition of the TEFR Interests (as defined and described in
Note 1
).
|
(2)
|
See
Note 5
.
|
(3)
|
See
Note 2
.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2016
|
|
2015
|
|
2014
|
||||||
Cash flows from operating activities
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
602,294
|
|
|
$
|
14,207
|
|
|
$
|
456,668
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
Depreciation and amortization
|
|
272,933
|
|
|
272,611
|
|
|
211,809
|
|
|||
Impairments
|
|
15,535
|
|
|
515,458
|
|
|
5,125
|
|
|||
Non-cash equity-based compensation expense
|
|
4,735
|
|
|
4,188
|
|
|
3,920
|
|
|||
Deferred income taxes
|
|
2,555
|
|
|
11,346
|
|
|
38,682
|
|
|||
Accretion and amortization of long-term obligations, net
|
|
(3,789
|
)
|
|
17,698
|
|
|
2,736
|
|
|||
Equity income, net – affiliates
|
|
(78,717
|
)
|
|
(71,251
|
)
|
|
(57,836
|
)
|
|||
Distributions from equity investment earnings – affiliates
|
|
82,185
|
|
|
82,054
|
|
|
62,967
|
|
|||
(Gain) loss on divestiture and other, net
(1)
|
|
14,641
|
|
|
(57,024
|
)
|
|
9
|
|
|||
Lower of cost or market inventory adjustments
|
|
168
|
|
|
443
|
|
|
—
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
|
||||||
(Increase) decrease in accounts receivable, net
|
|
(48,947
|
)
|
|
(4,371
|
)
|
|
1,399
|
|
|||
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net
|
|
58,359
|
|
|
1,006
|
|
|
(34,980
|
)
|
|||
Change in other items, net
|
|
(4,367
|
)
|
|
(720
|
)
|
|
3,996
|
|
|||
Net cash provided by operating activities
|
|
917,585
|
|
|
785,645
|
|
|
694,495
|
|
|||
Cash flows from investing activities
|
|
|
|
|
|
|
||||||
Capital expenditures
|
|
(479,993
|
)
|
|
(637,964
|
)
|
|
(805,005
|
)
|
|||
Contributions in aid of construction costs from affiliates
|
|
6,135
|
|
|
461
|
|
|
183
|
|
|||
Acquisitions from affiliates
|
|
(716,465
|
)
|
|
(10,903
|
)
|
|
(379,193
|
)
|
|||
Acquisitions from third parties
|
|
—
|
|
|
(3,514
|
)
|
|
(1,523,327
|
)
|
|||
Investments in equity affiliates
|
|
(27
|
)
|
|
(11,442
|
)
|
|
(64,278
|
)
|
|||
Distributions from equity investments in excess of cumulative earnings – affiliates
|
|
21,238
|
|
|
16,244
|
|
|
18,055
|
|
|||
Proceeds from the sale of assets to affiliates
|
|
623
|
|
|
925
|
|
|
402
|
|
|||
Proceeds from the sale of assets to third parties
|
|
45,490
|
|
|
145,916
|
|
|
12,988
|
|
|||
Proceeds from property insurance claims
|
|
17,465
|
|
|
—
|
|
|
—
|
|
|||
Net cash used in investing activities
|
|
(1,105,534
|
)
|
|
(500,277
|
)
|
|
(2,740,175
|
)
|
|||
Cash flows from financing activities
|
|
|
|
|
|
|
||||||
Borrowings, net of debt issuance costs
|
|
1,297,218
|
|
|
889,606
|
|
|
1,646,878
|
|
|||
Repayments of debt
|
|
(900,000
|
)
|
|
(610,000
|
)
|
|
(650,000
|
)
|
|||
Increase (decrease) in outstanding checks
|
|
2,079
|
|
|
(2,666
|
)
|
|
765
|
|
|||
Proceeds from the issuance of common and general partner units, net of offering expenses
|
|
25,000
|
|
|
57,353
|
|
|
704,489
|
|
|||
Proceeds from the issuance of Class C units
|
|
—
|
|
|
—
|
|
|
750,000
|
|
|||
Proceeds from the issuance of Series A Preferred units, net of offering expenses
|
|
686,937
|
|
|
—
|
|
|
—
|
|
|||
Distributions to unitholders
(2)
|
|
(671,938
|
)
|
|
(545,143
|
)
|
|
(408,621
|
)
|
|||
Distributions to noncontrolling interest owner
|
|
(13,784
|
)
|
|
(12,187
|
)
|
|
(15,149
|
)
|
|||
Net contributions from (distributions to) Anadarko
|
|
(23,491
|
)
|
|
(49,801
|
)
|
|
(16,392
|
)
|
|||
Above-market component of swap extensions with Anadarko
(2)
|
|
45,820
|
|
|
18,449
|
|
|
—
|
|
|||
Net cash provided by (used in) financing activities
|
|
447,841
|
|
|
(254,389
|
)
|
|
2,011,970
|
|
|||
Net increase (decrease) in cash and cash equivalents
|
|
259,892
|
|
|
30,979
|
|
|
(33,710
|
)
|
|||
Cash and cash equivalents at beginning of period
|
|
98,033
|
|
|
67,054
|
|
|
100,764
|
|
|||
Cash and cash equivalents at end of period
|
|
$
|
357,925
|
|
|
$
|
98,033
|
|
|
$
|
67,054
|
|
Supplemental disclosures
|
|
|
|
|
|
|
||||||
Acquisition of DBJV from Anadarko
|
|
$
|
(147,234
|
)
|
|
$
|
174,276
|
|
|
$
|
—
|
|
Net distributions to (contributions from) Anadarko of other assets
|
|
581
|
|
|
4,632
|
|
|
10,706
|
|
|||
Interest paid, net of capitalized interest
|
|
106,485
|
|
|
94,720
|
|
|
67,648
|
|
|||
Taxes paid (reimbursements received)
|
|
838
|
|
|
—
|
|
|
(90
|
)
|
|||
Capital lease asset transfer
(3)
|
|
—
|
|
|
—
|
|
|
4,833
|
|
(1)
|
Includes losses related to an incident at the DBM complex for the year ended December 31, 2015. See
Note 1
.
|
(2)
|
See
Note 5
.
|
(3)
|
For the year ended December 31, 2014, represents transfers of
$4.6 million
from other long-term assets associated with the capital lease component of a processing agreement.
|
|
|
Owned and
Operated
|
|
Operated
Interests
|
|
Non-Operated
Interests
|
|
Equity
Interests
|
||||
Gathering systems
|
|
11
|
|
|
4
|
|
|
5
|
|
|
2
|
|
Treating facilities
|
|
12
|
|
|
12
|
|
|
—
|
|
|
3
|
|
Natural gas processing plants/trains
|
|
20
|
|
|
5
|
|
|
—
|
|
|
2
|
|
NGL pipelines
|
|
2
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Natural gas pipelines
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Oil pipelines
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
|
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)
|
|
|
|
Non-Operated Marcellus Interest systems
|
|
33.75
|
%
|
Anadarko-Operated Marcellus Interest systems
|
|
33.75
|
%
|
Newcastle system
|
|
50
|
%
|
DBJV system
|
|
50
|
%
|
Springfield system
|
|
50.1
|
%
|
Full consolidation
|
|
|
|
Chipeta
(3)
|
|
75
|
%
|
(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.
|
thousands except unit and percent amounts
|
|
Acquisition
Date
|
|
Percentage
Acquired |
|
Deferred Purchase Price
Obligation - Anadarko
|
|
Borrowings
|
|
Cash
On Hand
|
|
Common Units
Issued
|
|
Class C Units
Issued to Anadarko
|
|
Series A
Preferred Units Issued
|
||||||||||
TEFR Interests
(1)
|
|
03/03/2014
|
|
Various
(1)
|
|
|
$
|
—
|
|
|
$
|
350,000
|
|
|
$
|
6,250
|
|
|
308,490
|
|
|
—
|
|
|
—
|
|
DBM
(2)
|
|
11/25/2014
|
|
100
|
%
|
|
—
|
|
|
475,000
|
|
|
298,327
|
|
|
—
|
|
|
10,913,853
|
|
|
—
|
|
|||
DBJV
(3)
|
|
03/02/2015
|
|
100
|
%
|
|
174,276
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Springfield
(4)
|
|
03/14/2016
|
|
100
|
%
|
|
—
|
|
|
247,500
|
|
|
—
|
|
|
2,089,602
|
|
|
—
|
|
|
14,030,611
|
|
(1)
|
The Partnership acquired a
20%
interest in each of TEG and TEP and a
33.33%
interest in FRP from Anadarko. These assets gather and transport NGLs primarily from the Anadarko and Denver-Julesburg (“DJ”) Basins. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, the Partnership issued
6,296
general partner units to the general partner in exchange for the general partner’s proportionate capital contribution of
$0.4 million
.
|
(2)
|
The Partnership acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, the Partnership changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which are collectively referred to as the “DBM complex” and serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. See
DBM acquisition
below for further information, including the final allocation of the purchase price.
|
(3)
|
The Partnership acquired Delaware Basin JV Gathering LLC (“DBJV”) from Anadarko. DBJV owns a
50%
interest in a gathering system and related facilities. The DBJV gathering system and related facilities (the “DBJV system”) are located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties, Texas. The Partnership will make a cash payment on March 31, 2020, to Anadarko as consideration for the acquisition of DBJV. At the acquisition date, the Partnership estimated the future payment would be
$282.8 million
, the net present value of which was
$174.3 million
. For further information, including revisions to the estimated future payment, see
DBJV acquisition—deferred purchase price obligation - Anadarko
below.
|
(4)
|
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, such interest being referred to in this report as the “Springfield interest.” 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.
|
|
|
Deferred purchase price obligation - Anadarko
|
|
Estimated future payment obligation
|
||||
Balance at March 2, 2015
–
Acquisition date
|
|
$
|
174,276
|
|
|
$
|
282,807
|
|
Accretion expense
(1)
|
|
14,398
|
|
|
|
|||
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
|
|
(1)
|
Accretion expense was recorded as a charge to Interest expense on the consolidated statements of operations.
|
(2)
|
Financing-related accretion revisions were recorded in Interest expense on the consolidated statements of operations.
|
(3)
|
Recorded as revisions within Common units on the consolidated balance sheets and consolidated statements of equity and partners’ capital.
|
thousands except per-unit amounts
Quarters Ended
|
|
Total Quarterly
Distribution
per Unit
|
|
Total Quarterly
Cash Distribution
|
|
Date of
Distribution
|
|||||
2014
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.625
|
|
|
$
|
98,749
|
|
|
May 2014
|
|
June 30
|
|
0.650
|
|
|
105,655
|
|
|
August 2014
|
|||
September 30
|
|
0.675
|
|
|
111,608
|
|
|
November 2014
|
|||
December 31
|
|
0.700
|
|
|
126,044
|
|
|
February 2015
|
|||
2015
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.725
|
|
|
$
|
133,203
|
|
|
May 2015
|
|
June 30
|
|
0.750
|
|
|
139,736
|
|
|
August 2015
|
|||
September 30
|
|
0.775
|
|
|
146,160
|
|
|
November 2015
|
|||
December 31
|
|
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
(1)
|
|
0.860
|
|
|
170,657
|
|
|
February 2017
|
(1)
|
The Board of Directors declared a cash distribution to the Partnership’s unitholders for the
fourth quarter
of
2016
of
$0.860
per unit, or
$170.7 million
in aggregate, including incentive distributions, but excluding distributions on Class C units (see
Class C unit distributions
below) and Series A Preferred units (see
Series A Preferred unit distributions
below). The cash distribution was paid on
February 13, 2017
, to unitholders of record at the close of business on
February 2, 2017
.
|
thousands except unit and per-unit amounts
|
|
Common Units
Issued
|
|
GP Units
Issued
(1)
|
|
Price Per
Unit
|
|
Underwriting
Discount and
Other Offering
Expenses
|
|
Net
Proceeds
|
||||||||
2014
|
|
|
|
|
|
|
|
|
|
|
||||||||
$125.0 million COP
(2)
|
|
1,133,384
|
|
|
23,132
|
|
|
$
|
73.48
|
|
|
$
|
1,738
|
|
|
$
|
83,245
|
|
November 2014 equity offering
(3)
|
|
8,620,153
|
|
|
153,061
|
|
|
70.85
|
|
|
18,615
|
|
|
602,967
|
|
|||
2015
|
|
|
|
|
|
|
|
|
|
|
||||||||
$500.0 million COP
(4)
|
|
873,525
|
|
|
—
|
|
|
$
|
66.61
|
|
|
$
|
805
|
|
|
$
|
57,385
|
|
(1)
|
Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution.
|
(2)
|
Represents common and general partner units issued during the year ended December 31, 2014, under the
$125.0 million
COP. Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2014, were
$85.0 million
. The price per unit in the table above represents an average price for all issuances under the $125.0 million COP during the year ended December 31, 2014. As of December 31, 2014, the Partnership had used all the capacity to issue common units under this registration statement.
|
(3)
|
Includes the issuance of
1,120,153
common units pursuant to the partial exercise of the underwriters’ over-allotment option, the net proceeds from which were
$77.0 million
. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain its
2.0%
interest in the Partnership.
|
(4)
|
Represents common units issued during the year ended December 31, 2015, pursuant to the Partnership’s registration statement filed with the SEC in August 2014 authorizing the issuance of up to an aggregate of
$500.0 million
of common units (the “$500.0 million COP”). Gross proceeds generated during the three months and year ended December 31, 2015, were
zero
and
$58.2 million
, respectively. Commissions paid during the three months and year ended December 31, 2015, were
zero
and
$0.6 million
, respectively. The price per unit in the table above represents an average price for all issuances under the $500.0 million COP during the year ended December 31, 2015.
|
|
|
Common
Units
|
|
Class C
Units
|
|
Series A
Preferred
Units
|
|
General
Partner
Units
|
|
Total
|
|||||
Balance at December 31, 2014
|
|
127,695,130
|
|
|
10,913,853
|
|
|
—
|
|
|
2,583,068
|
|
|
141,192,051
|
|
PIK Class C units
|
|
—
|
|
|
498,009
|
|
|
—
|
|
|
—
|
|
|
498,009
|
|
Long-Term Incentive Plan award vestings
|
|
8,310
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,310
|
|
$500.0 million COP
|
|
873,525
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
873,525
|
|
Balance at December 31, 2015
|
|
128,576,965
|
|
|
11,411,862
|
|
|
—
|
|
|
2,583,068
|
|
|
142,571,895
|
|
PIK Class C units
|
|
—
|
|
|
946,261
|
|
|
—
|
|
|
—
|
|
|
946,261
|
|
Springfield acquisition
|
|
2,089,602
|
|
|
—
|
|
|
14,030,611
|
|
|
—
|
|
|
16,120,213
|
|
April 2016 Series A units
|
|
—
|
|
|
—
|
|
|
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
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands except per-unit amounts
|
|
2016
|
|
2015
|
|
2014
|
||||||
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
591,331
|
|
|
$
|
4,106
|
|
|
$
|
442,643
|
|
Pre-acquisition net (income) loss allocated to Anadarko
|
|
(11,326
|
)
|
|
(79,386
|
)
|
|
(65,154
|
)
|
|||
Series A Preferred units interest in net (income) loss
(1)
|
|
(76,893
|
)
|
|
—
|
|
|
—
|
|
|||
General partner interest in net (income) loss
|
|
(236,561
|
)
|
|
(180,996
|
)
|
|
(120,980
|
)
|
|||
Common and Class C limited partners’ interest in net income (loss)
|
|
$
|
266,551
|
|
|
$
|
(256,276
|
)
|
|
$
|
256,509
|
|
Net income (loss) allocable to common units
(1)
|
|
$
|
226,611
|
|
|
$
|
(250,210
|
)
|
|
$
|
254,737
|
|
Net income (loss) allocable to Class C units
(1)
|
|
39,940
|
|
|
(6,066
|
)
|
|
1,772
|
|
|||
Common and Class C limited partners’ interest in net income (loss)
|
|
$
|
266,551
|
|
|
$
|
(256,276
|
)
|
|
$
|
256,509
|
|
Net income (loss) per unit
|
|
|
|
|
|
|
||||||
Common units – basic
|
|
$
|
1.74
|
|
|
$
|
(1.95
|
)
|
|
$
|
2.13
|
|
Common units – diluted
(2)
|
|
1.74
|
|
|
(1.95
|
)
|
|
2.12
|
|
|||
Weighted-average units outstanding
|
|
|
|
|
|
|
||||||
Common units – basic
|
|
130,253
|
|
|
128,345
|
|
|
119,822
|
|
|||
Class C units
(2)
|
|
11,945
|
|
|
11,114
|
|
|
1,106
|
|
|||
Series A Preferred units assuming conversion to common units
(2)
|
|
16,860
|
|
|
—
|
|
|
—
|
|
|||
Common units - diluted
(2)
|
|
130,253
|
|
|
128,345
|
|
|
120,928
|
|
(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 the year ended December 31, 2016, and the impact of Class C units would be anti-dilutive for the year ended December 31, 2015.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2016
|
|
2015
|
|
2014
|
||||||
Gains (losses) on commodity price swap agreements related to sales:
(1)
|
|
|
|
|
|
|
||||||
Natural gas sales
|
|
$
|
11,116
|
|
|
$
|
45,978
|
|
|
$
|
9,494
|
|
Natural gas liquids sales
|
|
59,918
|
|
|
145,258
|
|
|
113,866
|
|
|||
Total
|
|
71,034
|
|
|
191,236
|
|
|
123,360
|
|
|||
Losses on commodity price swap agreements related to purchases
(2)
|
|
(42,577
|
)
|
|
(124,944
|
)
|
|
(68,492
|
)
|
|||
Net gains (losses) on commodity price swap agreements
|
|
$
|
28,457
|
|
|
$
|
66,292
|
|
|
$
|
54,868
|
|
(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 - 2017 Swap Prices
|
|
2015 Market Prices
(1)
|
|
2016 Market Prices
(1)
|
|
2017 Market Prices
(1)
|
||||||||
Ethane
|
|
$
|
18.41
|
|
|
$
|
1.96
|
|
|
$
|
0.60
|
|
|
$
|
5.09
|
|
Propane
|
|
47.08
|
|
|
13.10
|
|
|
10.98
|
|
|
18.85
|
|
||||
Isobutane
|
|
62.09
|
|
|
19.75
|
|
|
17.23
|
|
|
26.83
|
|
||||
Normal butane
|
|
54.62
|
|
|
18.99
|
|
|
16.86
|
|
|
26.20
|
|
||||
Natural gasoline
|
|
72.88
|
|
|
52.59
|
|
|
26.15
|
|
|
41.84
|
|
||||
Condensate
|
|
76.47
|
|
|
52.59
|
|
|
34.65
|
|
|
45.40
|
|
||||
Natural gas (per MMBtu)
|
|
5.96
|
|
|
2.75
|
|
|
2.11
|
|
|
3.05
|
|
|
|
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 - 2017 Swap Prices
|
|
2017 Market Prices
(1)
|
||||||
Ethane
|
|
$
|
23.41
|
|
|
$
|
23.11
|
|
|
$
|
4.08
|
|
Propane
|
|
52.99
|
|
|
52.90
|
|
|
19.24
|
|
|||
Isobutane
|
|
74.02
|
|
|
73.89
|
|
|
25.79
|
|
|||
Normal butane
|
|
65.04
|
|
|
64.93
|
|
|
25.16
|
|
|||
Natural gasoline
|
|
81.82
|
|
|
81.68
|
|
|
45.01
|
|
|||
Condensate
|
|
81.82
|
|
|
81.68
|
|
|
53.55
|
|
|||
Natural gas (per MMBtu)
|
|
4.66
|
|
|
4.87
|
|
|
3.05
|
|
(1)
|
Represents the New York Mercantile Exchange forward strip price as of June 25, 2015, December 8, 2015 and December 1, 2016, for the 2015 Market Prices, 2016 Market Prices and 2017 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
|
|
2016
|
|
2015
|
|
2014
|
||||||
General and administrative expenses
|
|
$
|
29,360
|
|
|
$
|
22,896
|
|
|
$
|
20,249
|
|
Public company expenses
|
|
8,410
|
|
|
8,950
|
|
|
8,006
|
|
|||
Total reimbursement
|
|
$
|
37,770
|
|
|
$
|
31,846
|
|
|
$
|
28,255
|
|
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||
|
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
|
$
|
68.78
|
|
|
5,477
|
|
|
$
|
60.74
|
|
|
9,522
|
|
|
$
|
49.47
|
|
|
16,844
|
|
Vested
|
68.78
|
|
|
(5,477
|
)
|
|
60.69
|
|
|
(9,257
|
)
|
|
49.55
|
|
|
(13,122
|
)
|
|||
Granted
|
49.30
|
|
|
7,304
|
|
|
69.10
|
|
|
5,212
|
|
|
68.14
|
|
|
5,800
|
|
|||
Phantom units outstanding at end of year
|
49.30
|
|
|
7,304
|
|
|
68.78
|
|
|
5,477
|
|
|
60.74
|
|
|
9,522
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||
thousands
|
|
Purchases
|
|
Sales
|
||||||||||||||||||||
Cash consideration
|
|
$
|
3,965
|
|
|
$
|
10,903
|
|
|
$
|
22,943
|
|
|
$
|
623
|
|
|
$
|
925
|
|
|
$
|
402
|
|
Net carrying value
|
|
(3,366
|
)
|
|
(6,318
|
)
|
|
(12,210
|
)
|
|
(605
|
)
|
|
(972
|
)
|
|
(375
|
)
|
||||||
Partners’ capital adjustment
|
|
$
|
599
|
|
|
$
|
4,585
|
|
|
$
|
10,733
|
|
|
$
|
18
|
|
|
$
|
(47
|
)
|
|
$
|
27
|
|
|
|
Year ended December 31,
|
||||||||||
thousands
|
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues and other
(1)
|
|
$
|
1,228,232
|
|
|
$
|
1,220,639
|
|
|
$
|
1,203,974
|
|
Equity income, net
– affiliates
(1)
|
|
78,717
|
|
|
71,251
|
|
|
57,836
|
|
|||
Cost of product
(1)
|
|
80,455
|
|
|
167,354
|
|
|
127,930
|
|
|||
Operation and maintenance
(2)
|
|
72,330
|
|
|
77,061
|
|
|
71,386
|
|
|||
General and administrative
(3)
|
|
38,066
|
|
|
33,903
|
|
|
31,308
|
|
|||
Operating expenses
|
|
190,851
|
|
|
278,318
|
|
|
230,624
|
|
|||
Interest income
(4)
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
(5)
|
|
(7,747
|
)
|
|
14,398
|
|
|
—
|
|
|||
Proceeds from the issuance of common units, net of offering expenses
(6)
|
|
25,000
|
|
|
—
|
|
|
—
|
|
|||
Distributions to unitholders
(7)
|
|
382,711
|
|
|
314,200
|
|
|
234,024
|
|
|||
Above-market component of swap extensions with Anadarko
|
|
45,820
|
|
|
18,449
|
|
|
—
|
|
(1)
|
Represents amounts earned or incurred on and subsequent to the date of acquisition of the Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.
|
(2)
|
Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets.
|
(3)
|
Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see
WES LTIP
and
WGP LTIP and Anadarko Incentive Plans
within this
Note 5
) and amounts charged by Anadarko under the omnibus agreement.
|
(4)
|
Represents interest income recognized on the note receivable from Anadarko.
|
(5)
|
For the years ended December 31, 2016 and 2015, includes amounts related to the Deferred purchase price obligation - Anadarko (see
Note 2
and
Note 12
).
|
(6)
|
Represents proceeds from the issuance of
835,841
common units to WGP as partial funding for the acquisition of Springfield (see
Note 2
).
|
(7)
|
Represents distributions paid under the partnership agreement (see
Note 3
and
Note 4
).
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2016
|
|
2015
|
|
2014
|
||||||
Current income tax expense (benefit)
|
|
|
|
|
|
|
||||||
Federal income tax expense (benefit)
|
|
$
|
4,477
|
|
|
$
|
32,422
|
|
|
$
|
(114
|
)
|
State income tax expense (benefit)
|
|
1,340
|
|
|
1,764
|
|
|
493
|
|
|||
Total current income tax expense (benefit)
|
|
5,817
|
|
|
34,186
|
|
|
379
|
|
|||
Deferred income tax expense (benefit)
|
|
|
|
|
|
|
||||||
Federal income tax expense (benefit)
|
|
1,622
|
|
|
10,251
|
|
|
35,361
|
|
|||
State income tax expense (benefit)
|
|
933
|
|
|
1,095
|
|
|
3,321
|
|
|||
Total deferred income tax expense (benefit)
|
|
2,555
|
|
|
11,346
|
|
|
38,682
|
|
|||
Total income tax expense (benefit)
|
|
$
|
8,372
|
|
|
$
|
45,532
|
|
|
$
|
39,061
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands except percentages
|
|
2016
|
|
2015
|
|
2014
|
||||||
Income (loss) before income taxes
|
|
$
|
610,666
|
|
|
$
|
59,739
|
|
|
$
|
495,729
|
|
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
|
|
|
35,716
|
|
|||
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit)
|
|
117
|
|
|
298
|
|
|
864
|
|
|||
Texas margin tax expense (benefit)
(1)
|
|
2,093
|
|
|
2,411
|
|
|
2,481
|
|
|||
Income tax expense (benefit)
|
|
$
|
8,372
|
|
|
$
|
45,532
|
|
|
$
|
39,061
|
|
Effective tax rate
|
|
1
|
%
|
|
76
|
%
|
|
8
|
%
|
(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
|
|
2016
|
|
2015
|
||||
Depreciable property
|
|
$
|
(4,976
|
)
|
|
$
|
(138,159
|
)
|
Credit carryforwards
|
|
498
|
|
|
512
|
|
||
Other intangible assets
|
|
(1,928
|
)
|
|
(2,070
|
)
|
||
Other
|
|
4
|
|
|
13
|
|
||
Net long-term deferred income tax liabilities
|
|
$
|
(6,402
|
)
|
|
$
|
(139,704
|
)
|
|
|
|
|
December 31,
|
||||||
thousands
|
|
Estimated Useful Life
|
|
2016
|
|
2015
|
||||
Land
|
|
n/a
|
|
$
|
4,012
|
|
|
$
|
3,744
|
|
Gathering systems and processing complexes
|
|
3 to 47 years
|
|
6,462,053
|
|
|
6,061,004
|
|
||
Pipelines and equipment
|
|
15 to 45 years
|
|
139,646
|
|
|
136,290
|
|
||
Assets under construction
|
|
n/a
|
|
226,626
|
|
|
329,887
|
|
||
Other
|
|
3 to 40 years
|
|
29,605
|
|
|
25,853
|
|
||
Total property, plant and equipment
|
|
|
|
6,861,942
|
|
|
6,556,778
|
|
||
Accumulated depreciation
|
|
|
|
1,812,010
|
|
|
1,697,999
|
|
||
Net property, plant and equipment
|
|
|
|
$
|
5,049,932
|
|
|
$
|
4,858,779
|
|
|
|
December 31,
|
||||||
thousands
|
|
2016
|
|
2015
|
||||
Gross carrying amount
|
|
$
|
868,035
|
|
|
$
|
868,035
|
|
Accumulated amortization
|
|
(64,337
|
)
|
|
(35,908
|
)
|
||
Other intangible assets
|
|
$
|
803,698
|
|
|
$
|
832,127
|
|
|
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, 2014
|
$
|
25,933
|
|
|
$
|
44,315
|
|
|
$
|
56,336
|
|
|
$
|
121,337
|
|
|
$
|
16,790
|
|
|
$
|
198,793
|
|
|
$
|
170,988
|
|
|
$
|
634,492
|
|
Investment earnings (loss), net of amortization
|
(3,200
|
)
|
|
14,770
|
|
|
2,292
|
|
|
23,570
|
|
|
586
|
|
|
16,088
|
|
|
17,145
|
|
|
71,251
|
|
||||||||
Contributions
|
—
|
|
|
8,512
|
|
|
—
|
|
|
(432
|
)
|
|
—
|
|
|
1,880
|
|
|
1,482
|
|
|
11,442
|
|
||||||||
Distributions
|
(5,611
|
)
|
|
(14,188
|
)
|
|
(4,233
|
)
|
|
(24,248
|
)
|
|
(803
|
)
|
|
(16,340
|
)
|
|
(16,631
|
)
|
|
(82,054
|
)
|
||||||||
Distributions in excess of cumulative earnings
(8)
|
—
|
|
|
(2,970
|
)
|
|
(3,482
|
)
|
|
(3,138
|
)
|
|
(290
|
)
|
|
(5,618
|
)
|
|
(746
|
)
|
|
(16,244
|
)
|
||||||||
Balance at December 31, 2015
|
$
|
17,122
|
|
|
$
|
50,439
|
|
|
$
|
50,913
|
|
|
$
|
117,089
|
|
|
$
|
16,283
|
|
|
$
|
194,803
|
|
|
$
|
172,238
|
|
|
$
|
618,887
|
|
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
|
|
(1)
|
The Partnership has a
14.81%
interest in Fort Union, a joint venture that owns a gathering pipeline and treating facilities in the Powder River Basin. Anadarko is the construction manager and physical operator of the Fort Union facilities. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require
65%
or unanimous approval of the owners.
|
(2)
|
The Partnership has a
10%
interest in White Cliffs, a limited liability company that owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than
75%
approval of the members.
|
(3)
|
The Partnership has a
22%
interest in Rendezvous, a limited liability company that operates gas gathering facilities in Southwestern Wyoming. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the members’ gas servicing agreements, require unanimous approval of the members.
|
(4)
|
The Partnership has a
25%
interest in the Mont Belvieu JV, an entity formed to design, construct, and own
two
fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require
50%
or unanimous approval of the owners.
|
(5)
|
The Partnership has a
20%
interest in TEG, an entity that consists of
two
NGL gathering systems that link natural gas processing plants to TEP. Enbridge Midcoast Energy, LP (“Enbridge”) is the operator of the two gathering systems. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the delegation, creation, appointment, or removal of officer positions require more than
50%
approval of the members.
|
(6)
|
The Partnership has a
20%
interest in TEP, which consists of an NGL pipeline that originates in Skellytown, Texas and extends to Mont Belvieu, Texas. Enterprise Products Operating LLC (“Enterprise”) is the operator of TEP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than
50%
approval of the members.
|
(7)
|
The Partnership has a
33.33%
interest in the FRP, an NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. Enterprise is the operator of FRP. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require more than
50%
approval of the members.
|
(8)
|
Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2016
|
|
2015
|
|
2014
|
||||||
Consolidated Statements of Income
|
|
|
|
|
|
|
||||||
Revenues
|
|
$
|
687,554
|
|
|
$
|
667,554
|
|
|
$
|
548,629
|
|
Operating income
|
|
428,454
|
|
|
359,899
|
|
|
336,188
|
|
|||
Net income
|
|
427,511
|
|
|
359,443
|
|
|
333,705
|
|
|
|
December 31,
|
||||||
thousands
|
|
2016
|
|
2015
|
||||
Consolidated Balance Sheets
|
|
|
|
|
||||
Current assets
|
|
$
|
118,472
|
|
|
$
|
154,937
|
|
Property, plant and equipment, net
|
|
2,626,466
|
|
|
2,716,078
|
|
||
Other assets
|
|
39,802
|
|
|
43,713
|
|
||
Total assets
|
|
$
|
2,784,740
|
|
|
$
|
2,914,728
|
|
Current liabilities
|
|
63,468
|
|
|
78,116
|
|
||
Non-current liabilities
|
|
6,662
|
|
|
9,072
|
|
||
Equity
|
|
2,714,610
|
|
|
2,827,540
|
|
||
Total liabilities and equity
|
|
$
|
2,784,740
|
|
|
$
|
2,914,728
|
|
|
|
December 31,
|
||||||
thousands
|
|
2016
|
|
2015
|
||||
Trade receivables, net
|
|
$
|
192,808
|
|
|
$
|
143,557
|
|
Other receivables, net
|
|
30,415
|
|
|
49,772
|
|
||
Total accounts receivable, net
|
|
$
|
223,223
|
|
|
$
|
193,329
|
|
|
|
December 31,
|
||||||
thousands
|
|
2016
|
|
2015
|
||||
Natural gas liquids inventory
|
|
$
|
7,126
|
|
|
$
|
2,403
|
|
Imbalance receivables
|
|
3,483
|
|
|
2,122
|
|
||
Prepaid insurance
|
|
2,257
|
|
|
2,296
|
|
||
Other
|
|
—
|
|
|
1,034
|
|
||
Total other current assets
|
|
$
|
12,866
|
|
|
$
|
7,855
|
|
|
|
December 31,
|
||||||
thousands
|
|
2016
|
|
2015
|
||||
Accrued capital expenditures
|
|
$
|
79,253
|
|
|
$
|
61,454
|
|
Accrued plant purchases
|
|
44,538
|
|
|
16,425
|
|
||
Accrued interest expense
|
|
39,826
|
|
|
26,194
|
|
||
Short-term asset retirement obligations
|
|
3,114
|
|
|
3,677
|
|
||
Short-term remediation and reclamation obligations
|
|
630
|
|
|
1,136
|
|
||
Income taxes payable
|
|
1,006
|
|
|
770
|
|
||
Other
|
|
532
|
|
|
9,363
|
|
||
Total accrued liabilities
|
|
$
|
168,899
|
|
|
$
|
119,019
|
|
|
|
Year Ended December 31,
|
||||||
thousands
|
|
2016
|
|
2015
|
||||
Carrying amount of asset retirement obligations at beginning of year
|
|
$
|
130,631
|
|
|
$
|
119,855
|
|
Liabilities incurred
|
|
5,515
|
|
|
9,490
|
|
||
Liabilities settled
|
|
(10,650
|
)
|
|
(7,905
|
)
|
||
Accretion expense
|
|
6,794
|
|
|
6,381
|
|
||
Revisions in estimated liabilities
|
|
10,117
|
|
|
2,810
|
|
||
Carrying amount of asset retirement obligations at end of year
|
|
$
|
142,407
|
|
|
$
|
130,631
|
|
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||||||||||||||
thousands
|
|
Principal
|
|
Carrying
Value
|
|
Fair
Value
(1)
|
|
Principal
|
|
Carrying
Value
|
|
Fair
Value
(1)
|
||||||||||||
2021 Notes
|
|
$
|
500,000
|
|
|
$
|
494,734
|
|
|
$
|
536,252
|
|
|
$
|
500,000
|
|
|
$
|
493,711
|
|
|
$
|
513,645
|
|
2022 Notes
|
|
670,000
|
|
|
668,634
|
|
|
681,723
|
|
|
670,000
|
|
|
668,432
|
|
|
595,744
|
|
||||||
2018 Notes
|
|
350,000
|
|
|
349,188
|
|
|
351,531
|
|
|
350,000
|
|
|
348,706
|
|
|
339,293
|
|
||||||
2044 Notes
|
|
600,000
|
|
|
593,132
|
|
|
615,753
|
|
|
400,000
|
|
|
389,707
|
|
|
321,499
|
|
||||||
2025 Notes
|
|
500,000
|
|
|
490,971
|
|
|
492,499
|
|
|
500,000
|
|
|
490,095
|
|
|
422,285
|
|
||||||
2026 Notes
|
|
500,000
|
|
|
494,802
|
|
|
518,441
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
RCF
|
|
—
|
|
|
—
|
|
|
—
|
|
|
300,000
|
|
|
300,000
|
|
|
300,000
|
|
||||||
Total long-term debt
|
|
$
|
3,120,000
|
|
|
$
|
3,091,461
|
|
|
$
|
3,196,199
|
|
|
$
|
2,720,000
|
|
|
$
|
2,690,651
|
|
|
$
|
2,492,466
|
|
(1)
|
Fair value is measured using the market approach and Level 2 inputs.
|
thousands
|
|
Carrying Value
|
||
Balance at December 31, 2014
|
|
$
|
2,408,785
|
|
RCF borrowings
|
|
400,000
|
|
|
Issuance of 2025 Notes
|
|
500,000
|
|
|
Repayments of RCF borrowings
|
|
(610,000
|
)
|
|
Other
|
|
(8,134
|
)
|
|
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
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2016
|
|
2015
|
|
2014
|
||||||
Third parties
|
|
|
|
|
|
|
||||||
Long-term debt
|
|
$
|
121,832
|
|
|
$
|
102,058
|
|
|
$
|
81,495
|
|
Amortization of debt issuance costs and commitment fees
|
|
6,398
|
|
|
5,734
|
|
|
5,103
|
|
|||
Capitalized interest
|
|
(5,562
|
)
|
|
(8,318
|
)
|
|
(9,832
|
)
|
|||
Total interest expense – third parties
|
|
122,668
|
|
|
99,474
|
|
|
76,766
|
|
|||
Affiliates
|
|
|
|
|
|
|
||||||
Deferred purchase price obligation – Anadarko
(1)
|
|
(7,747
|
)
|
|
14,398
|
|
|
—
|
|
|||
Total interest expense – affiliates
|
|
(7,747
|
)
|
|
14,398
|
|
|
—
|
|
|||
Interest expense
|
|
$
|
114,921
|
|
|
$
|
113,872
|
|
|
$
|
76,766
|
|
(1)
|
See
Note 2
for a discussion of the Deferred purchase price obligation - Anadarko.
|
thousands
|
|
Operating Leases
|
||
2017
|
|
$
|
7,322
|
|
2018
|
|
898
|
|
|
2019
|
|
764
|
|
|
2020
|
|
122
|
|
|
2021
|
|
—
|
|
|
Thereafter
|
|
—
|
|
|
Total
|
|
$
|
9,106
|
|
thousands except per-unit amounts
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
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
|
|
||||
2015
|
|
|
|
|
|
|
|
||||||||
Total revenues and other
|
$
|
437,006
|
|
|
$
|
465,993
|
|
|
$
|
432,515
|
|
|
$
|
416,558
|
|
Equity income, net – affiliates
|
18,220
|
|
|
18,941
|
|
|
21,976
|
|
|
12,114
|
|
||||
Gain (loss) on divestiture and other, net
|
(6
|
)
|
|
—
|
|
|
77,254
|
|
|
(20,224
|
)
|
||||
Operating income (loss)
(2)
|
(122,333
|
)
|
|
170,713
|
|
|
226,432
|
|
|
(117,482
|
)
|
||||
Net income (loss)
(2)
|
(153,267
|
)
|
|
135,159
|
|
|
186,325
|
|
|
(154,010
|
)
|
||||
Net income (loss) attributable to Western Gas Partners, LP
(2)
|
(156,493
|
)
|
|
132,343
|
|
|
184,137
|
|
|
(155,881
|
)
|
||||
Net income (loss) per common unit – basic and diluted
(1) (2)
|
(1.61
|
)
|
|
0.46
|
|
|
0.79
|
|
|
(1.60
|
)
|
(1)
|
Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets (as defined in
Note 1—Summary of Significant Accounting Policies
).
|
(2)
|
Includes impairments at the Red Desert complex in the first and fourth quarters of 2015 and at the Hilight system in the fourth quarter of 2015. See
Note 7—Property, Plant and Equipment
.
|
Name
|
|
Age
|
|
Position with Western Gas Holdings, LLC
|
|
Robert G. Gwin
|
|
53
|
|
|
Chairman of the Board
|
Donald R. Sinclair
|
|
59
|
|
|
President, Chief Executive Officer and Director (through February 13, 2017)
|
Benjamin M. Fink
|
|
46
|
|
|
President, Chief Executive Officer, Chief Financial Officer and Treasurer
|
Craig W. Collins
|
|
44
|
|
|
Senior Vice President and Chief Operating Officer (since February 13, 2017)
|
Jacqueline A. Dimpel
|
|
50
|
|
|
Senior Vice President (through April 8, 2016)
|
Philip H. Peacock
|
|
45
|
|
|
Senior Vice President, General Counsel and Corporate Secretary
|
Steven D. Arnold
|
|
56
|
|
|
Director
|
Milton Carroll
|
|
66
|
|
|
Director
|
James R. Crane
|
|
63
|
|
|
Director
|
Darrell E. Hollek
|
|
59
|
|
|
Director
|
Robert K. Reeves
|
|
59
|
|
|
Director
|
David J. Tudor
|
|
57
|
|
|
Director
|
Benjamin M. Fink
Age: 46
Houston, Texas
Director since:
February 2017
Not Independent
Officer since:
2009
|
Biography/Qualifications
Benjamin M. Fink has served as President, Chief Executive Officer, Chief Financial Officer and Treasurer of our general partner and WGP GP since February 2017. He previously served as Senior Vice President and Chief Financial Officer of our general partner from 2009 to February 2017, and as Senior Vice President, Chief Financial Officer and Treasurer of WGP GP from September 2012 to February 2017. Mr. Fink currently serves as a Senior Vice President at Anadarko. He was Director, Finance of Anadarko from 2007 to 2009, during which time he was responsible for principal oversight of the finance operations of an Anadarko subsidiary, Anadarko Algeria Company, LLC. From 2006 to 2007, he served as an independent financial consultant to Anadarko in its Beijing, China and Rio de Janeiro, Brazil offices. From 2001 until 2006, he held executive management positions at Prosoft Learning Corporation, including serving as its President and Chief Executive Officer from 2004 until that company’s sale in 2006. From 2000 to 2001 he co-founded and served as Chief Operating Officer and Chief Financial Officer of Meta4 Group Limited, an online direct marketer based in Hong Kong and Tokyo. Previously, he held positions of increasing responsibility at Prudential Capital Group and Prudential Asset Management Asia, where he focused on the negotiation, structuring and execution of private debt and equity investments.
|
|
|
Craig W. Collins
Age: 44
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.
|
|
|
Jacqueline A. Dimpel
Age: 50
Houston, Texas
Officer from:
February 2014 to
April 2016
|
Biography/Qualifications
From February 2014 to April 2016, Jacqueline A. Dimpel served as Senior Vice President and principal operating officer for our general partner and for WGP GP. She also served as Vice President of Midstream for Anadarko since December 2013. From 2006 through April 2016, Ms. Dimpel served in a variety of technical, operational and planning positions, including Business Advisor for U.S. Onshore Operations and Midstream Operations Manager for the Southern and Appalachia region. Prior to joining Anadarko, Ms. Dimpel served in engineering roles of increasing responsibility with ExxonMobil.
|
|
|
Philip H. Peacock
Age: 45
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 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 Western Gas, Mr. Peacock was a partner practicing corporate and securities law at the law firm of Andrews Kurth LLP, which he joined in 2003. He is licensed to practice law in the state of Texas.
|
|
|
Steven D. Arnold
Age: 56
Houston, Texas
Director since:
February 2014
Independent
|
Biography/Qualifications
Steven D. Arnold has served as a director of our general partner and as a member of the Special Committee and Audit Committee of the Board of Directors since February 2014. Mr. Arnold served on the Board of Directors of the general partner of Spectra Energy Partners, LP from 2007 to December 2013, during which time he served on that board’s Audit Committee and Conflicts Committee. He served as Chairman of each of those committees at separate times during his board membership. Mr. Arnold is engaged in private investment management and consulting services in Houston, Texas through 3 Lights Management Co., serving as its President since inception in 2000. Mr. Arnold has over ten years of institutional investment management experience with Prudential Financial, Inc. Mr. Arnold brings strong risk assessment and strategic expertise to the board.
|
|
|
Milton Carroll
Age: 66
Houston, Texas
Director since:
2008
Independent
|
Biography/Qualifications
Milton Carroll has served as a director of our general partner and as Chairman of the Special Committee of the Board of Directors since 2008. Mr. Carroll currently serves as Executive Chairman of Houston-based CenterPoint Energy, Inc., where he has been a director since 1992. He also serves as Chairman of Health Care Services Corporation (a Chicago-based company operating through its Blue Cross and Blue Shield divisions in Illinois, Texas, Oklahoma, New Mexico, and Montana) and as a director of Halliburton Company, where he serves as a member of the Compensation Committee and the Nominating and Corporate Governance Committee. From 2010 to July 2016, Mr. Carroll served as a director of LyondellBasell Industries N.V., where he served as a member of the Nominating and Governance Committee and the Compensation Committee, and from November 2011 to January 2014, he served as a director of the general partner of LRR Energy, LP. Mr. Carroll also served as a director of EGL, Inc. from 2003 until 2007 and as a director of the general partner of DCP Midstream Partners, LP from 2005 to 2006.
|
|
|
James R. Crane
Age: 63
Houston, Texas
Director since:
2008
Independent
|
Biography/Qualifications
James R. Crane has served as a director of our general partner and as a member of the Special Committee and Audit Committee of the Board of Directors since April 2008. In November 2011, Mr. Crane became the principal owner and Chairman of the Houston Astros Baseball Club. Mr. Crane is also the Chairman and Chief Executive Officer of Crane Capital Group Inc., an investment management company he founded. Crane Capital Group currently invests in transportation, power distribution, real estate and asset management. Its holdings include Crane Worldwide Logistics, a premier global provider of customized transportation and logistics services with 54 offices in 20 countries. Prior to founding Crane Capital Group Inc., he was founder, Chairman and Chief Executive Officer of EGL, Inc., a global transportation, supply chain management and information services company, from 1984 until its sale in 2007. Mr. Crane currently serves as a director of Nabors Industries Ltd., an international drilling contractor and well-services provider. From February 2010 to February 2012, he served as a director of Fort Dearborn Life Insurance Company, a subsidiary of Health Care Service Corporation, and from 1999 to 2007 he served as a director of HCC Insurance Holdings, Inc.
|
|
|
Darrell E. Hollek
Age: 59
Houston, Texas
Director since:
May 2015
Not Independent
|
Biography/Qualifications
Darrell E. Hollek has served as a director of our general partner and as a director of WGP GP since May 2015. Mr. Hollek was named Executive Vice President, Operations of Anadarko in August 2016. 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: 59
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: 57
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.
|
Officers of Our General Partner
|
|
Time
Allocated
|
|
Anadarko Corporate Officer
|
Donald R. Sinclair
|
|
75.0%
|
|
Yes
|
Benjamin M. Fink
|
|
90.0%
|
|
Yes
|
Jacqueline A. Dimpel
|
|
25.0%
|
|
Yes
|
Philip H. Peacock
|
|
50.0%
|
|
No
|
•
|
base salary;
|
•
|
annual cash incentives;
|
•
|
equity-based compensation, which includes equity-based compensation under Anadarko’s 2012 Omnibus Incentive Compensation Plan (the “Omnibus Plan”); and
|
•
|
Anadarko’s other benefits, including welfare and retirement benefits, severance benefits and change of control benefits, plus other benefits on the same basis as other eligible Anadarko employees.
|
•
|
retirement benefits to match competitive practices in Anadarko’s industry, including participation in Anadarko’s employee savings plan, savings restoration plan, retirement plan and retirement restoration plan;
|
•
|
severance benefits under the Anadarko Officer Severance Plan;
|
•
|
certain change of control benefits under key employee change of control contracts;
|
•
|
director and officer indemnification agreements;
|
•
|
a limited number of perquisites, including financial counseling, tax preparation and estate planning, an executive physical program, management life insurance, voluntary participation in the Deferred Compensation Plan, and personal excess liability insurance; and
|
•
|
benefits, including medical, dental, vision, flexible spending and health savings accounts, paid time off, life insurance and disability coverage, which are also provided to all other eligible U.S.-based Anadarko employees.
|
Name and Principal Position
|
|
Year
|
|
Salary
($)
(1)
|
|
Bonus
($)
|
|
Stock
Awards
($)
(2)
|
|
Option
Awards
($)
(3)
|
|
Non-Equity
Incentive Plan Compensation
($)
(4)
|
|
All Other
Compensation
($)
(5)
|
|
Total
($)
|
|||||||
Donald R. Sinclair
|
|
2016
|
|
356,971
|
|
|
—
|
|
|
1,875,920
|
|
|
615,378
|
|
|
342,692
|
|
|
116,869
|
|
|
3,307,830
|
|
President and
|
|
2015
|
|
350,481
|
|
|
—
|
|
|
828,646
|
|
|
449,573
|
|
|
336,462
|
|
|
104,969
|
|
|
2,070,131
|
|
Chief Executive Officer
|
2014
|
|
304,327
|
|
|
—
|
|
|
807,851
|
|
|
436,272
|
|
|
292,154
|
|
|
77,370
|
|
|
1,917,974
|
|
|
Benjamin M. Fink
|
|
2016
|
|
332,135
|
|
|
—
|
|
|
1,634,281
|
|
|
401,340
|
|
|
259,066
|
|
|
108,526
|
|
|
2,735,348
|
|
Senior Vice President, Chief
|
|
2015
|
|
341,135
|
|
|
—
|
|
|
672,651
|
|
|
364,951
|
|
|
266,085
|
|
|
102,170
|
|
|
1,746,992
|
|
Financial Officer and Treasurer
|
2014
|
|
300,635
|
|
|
—
|
|
|
646,283
|
|
|
349,017
|
|
|
234,495
|
|
|
76,436
|
|
|
1,606,866
|
|
|
Jacqueline A. Dimpel
|
|
2016
|
|
24,231
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,242
|
|
|
31,473
|
|
Senior Vice President
|
|
2015
|
|
93,462
|
|
|
—
|
|
|
138,778
|
|
|
75,281
|
|
|
72,900
|
|
|
27,992
|
|
|
408,413
|
|
|
|
2014
|
|
82,260
|
|
|
—
|
|
|
273,490
|
|
|
139,580
|
|
|
64,163
|
|
|
20,945
|
|
|
580,438
|
|
Philip H. Peacock
|
|
2016
|
|
129,938
|
|
|
—
|
|
|
100,020
|
|
|
—
|
|
|
62,370
|
|
|
42,427
|
|
|
334,755
|
|
Vice President, General Counsel
|
|
2015
|
|
134,935
|
|
|
—
|
|
|
85,010
|
|
|
—
|
|
|
64,769
|
|
|
40,413
|
|
|
325,127
|
|
and Corporate Secretary
|
|
2014
|
|
128,510
|
|
|
—
|
|
|
87,515
|
|
|
—
|
|
|
61,685
|
|
|
30,766
|
|
|
308,476
|
|
(1)
|
The amounts in this column reflect the base salary compensation allocated to us by Anadarko for the years ended December 31,
2016
,
2015
and
2014
. Ms. Dimpel’s amount reflects base salary compensation earned and allocated through April 8, 2016.
|
(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 21—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,
2016
(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
2016
, 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
2016
, 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,
2016
, and allocated to us for the years ended December 31,
2015
and
2014
. The
2016
amounts represent payments which were earned in
2016
and are expected to be paid in early
2017
, the
2015
amounts represent payments which were earned in
2015
and paid in early
2016
and the
2014
amounts represent the payments which were earned in
2014
and paid in early
2015
. For an explanation of the
2016
annual incentive plan awards, read
Compensation Discussion and Analysis – Analysis of
2016
Compensation Actions – Performance-Based Annual Cash Incentives (Bonuses),
contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
March 31, 2017
.
|
(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,
2016
,
2015
and
2014
. The
2016
allocated expenses are detailed in the table below:
|
Name
|
|
Retirement Plan Expense
|
|
Savings Plan
Expense
|
||||
Donald R. Sinclair
|
|
$
|
82,342
|
|
|
$
|
34,527
|
|
Benjamin M. Fink
|
|
76,469
|
|
|
32,057
|
|
||
Jacqueline A. Dimpel
|
|
5,166
|
|
|
2,076
|
|
||
Philip H. Peacock
|
|
29,901
|
|
|
12,525
|
|
|
|
|
|
|
|
|
|
|
|
All
Other
Stock
Awards:
Number of
Shares of
Stock or
Units
(#)
(3)
|
|
All Other
Option
Awards:
Number of
Securities
Underlying
Options
(#)
(4)
|
|
Exercise
or
Base Price
of Option
Awards
($/Sh)
|
|
Grant
Date
Fair Value
of Stock
and
Option
Awards
($)
(5)
|
||||||||||||||
|
|
Estimated Future Payouts
Under Non-Equity
Incentive Plan Awards
(1)
|
|
Estimated Future Payouts Under
Equity Incentive Plan Awards
(2)
|
|
|
|
|
||||||||||||||||||||||
Name and Grant Date
|
|
Threshold
($)
|
|
Target
($)
|
|
Maximum
($)
|
|
Threshold
(#)
|
|
Target
(#)
|
|
Maximum
(#)
|
|
|
|
|
||||||||||||||
Donald R. Sinclair
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
285,577
|
|
|
342,692
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
11/10/16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,122
|
|
|
|
|
|
|
750,004
|
|
||||||||
11/10/16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,971
|
|
|
|
|
|
|
431,265
|
|
||||||||
11/10/16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29,733
|
|
|
61.87
|
|
|
615,378
|
|
|||||||
11/10/16
|
|
|
|
|
|
|
|
3,948
|
|
|
9,870
|
|
|
19,740
|
|
|
|
|
|
|
|
|
694,651
|
|
||||||
Benjamin M. Fink
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
215,888
|
|
|
259,066
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
11/10/16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,547
|
|
|
|
|
|
|
900,004
|
|
||||||||
11/10/16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,546
|
|
|
|
|
|
|
281,255
|
|
||||||||
11/10/16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,391
|
|
|
61.87
|
|
|
401,340
|
|
|||||||
11/10/16
|
|
|
|
|
|
|
|
2,575
|
|
|
6,437
|
|
|
12,874
|
|
|
|
|
|
|
|
|
453,022
|
|
||||||
Jacqueline A. Dimpel
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Philip H. Peacock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
51,975
|
|
|
62,370
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
11/10/16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,996
|
|
|
|
|
|
|
100,020
|
|
(1)
|
Reflects the estimated
2016
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
2016
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
2016
Compensation Actions — Performance-Based Annual Cash Incentives (Bonuses)
contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
March 31, 2017
.
|
(2)
|
Reflects the estimated future payout allocable to us under Anadarko’s performance units awarded in
2016
. Under the performance unit program, participants may earn from 0% to 200% of the targeted award based on Anadarko’s relative total shareholder return performance over a specified performance period. The performance units granted to Messrs. Sinclair and Fink on November 10, 2016, are subject to a three-year performance period. If earned, the awards are to be paid in cash rather than equity. The threshold value represents the minimum payment (other than zero) that may be earned. For additional discussion of Anadarko’s performance unit awards, read
Compensation Discussion and Analysis — Analysis of
2016
Compensation Actions — Equity Compensation
contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
March 31, 2017
.
|
(3)
|
Reflects the allocable number of restricted stock shares and restricted stock units awarded in
2016
under the Omnibus Plan. These awards vest equally over three years, beginning with the first anniversary of the grant date. For restricted stock shares, dividends are paid current. For restricted stock units, dividend equivalents are reinvested in shares of Anadarko common stock and paid upon the applicable vesting of the underlying award. Also included are the 12,122 and 14,547 allocated special restricted stock units awarded in 2016 under the Omnibus Plan to Messrs. Sinclair and Fink, respectively, which will vest in four years from grant date, provided Messrs. Sinclair and Fink remain employed by Anadarko until such date.
|
(4)
|
Reflects the allocable number of Anadarko stock options each named executive officer was awarded in
2016
. These awards vest equally over three years, beginning with the first anniversary of the date of grant and have a term of seven years.
|
(5)
|
The amounts included in the Grant Date Fair Value of Stock and Option Awards column represent the expected allocation to us of the grant date fair value of the awards made to named executives in
2016
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 21—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,
2016
(which is not, and shall not be deemed to be, incorporated by reference herein).
|
(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)
|
The restricted stock units and shares will vest pro-rate 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 converted into shares of unrestricted common stock, less applicable withholding taxes. For restricted stock shares, dividends are paid current. For restricted stock units, dividend equivalents are accrued and reinvested in additional shares of common stock, less applicable withholding taxes. For the 12,122 and 14,547 allocated special restricted stock units received in November 2016 by Messrs. Sinclair and Fink, respectively, and their corresponding dividend unit equivalents, these will vest in four years from grant date, provided Messrs. Sinclair and Fink remain employed by Anadarko until such date.
|
(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, 2016, 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 ranking as of December 31, 2016 are: 128% for the 2013 grant, 100% for the 2014 grant, and 100% for the 2015 grant. For awards granted in 2016 with the performance period beginning in 2017, 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)
|
||||
Donald R. Sinclair
|
|
—
|
|
|
—
|
|
|
8,294
|
|
|
419,743
|
|
Benjamin M. Fink
|
|
5,000
|
|
|
40,068
|
|
|
6,460
|
|
|
328,559
|
|
Jacqueline A. Dimpel
|
|
—
|
|
|
—
|
|
|
2,133
|
|
|
117,820
|
|
Philip H. Peacock
|
|
—
|
|
|
—
|
|
|
970
|
|
|
42,825
|
|
(1)
|
Shares acquired and values realized on exercise include options exercised in
2016
. 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
2016
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. Sinclair
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Cash Severance
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Mr. Sinclair
(1)
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Prorated Portion of Performance Unit Awards
(2)
|
$
|
397,507
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total
|
$
|
397,507
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
As of December 31, 2016, Mr. Sinclair was eligible for retirement.
|
(2)
|
Under the terms of the performance unit agreements, retirement-eligible participants receive a prorated payout, paid after the end of the performance period, based on actual performance and the number of months worked during the performance period. However, the performance unit awards granted on November 10, 2016, are not included in the table above as the treatment described in the preceding sentence 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 a retirement that occurred on December 31, 2016. Mr. Sinclair’s value reflects an estimated payout based on performance to date through December 31,
2016
, which is not indicative of the payout that he will receive at the end of the performance period based on actual performance.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Cash Severance
(1)
|
$
|
1,102,500
|
|
|
$
|
954,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Pro-rata Bonus
(2)
|
342,692
|
|
|
259,066
|
|
|
—
|
|
|
—
|
|
||||
Accelerated Anadarko Equity Awards
(3)
|
5,215,385
|
|
|
4,226,195
|
|
|
—
|
|
|
211,630
|
|
||||
Health and Welfare Benefits
(4)
|
89,865
|
|
|
39,017
|
|
|
—
|
|
|
—
|
|
||||
Total
|
$
|
6,750,442
|
|
|
$
|
5,478,278
|
|
|
$
|
—
|
|
|
$
|
211,630
|
|
(1)
|
Messrs. Sinclair’s and Fink’s values assume two times base salary plus one times target bonus multiplied by their allocation percentages in effect as of December 31,
2016
. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(2)
|
Payment, if provided, will be paid at the end of the performance period based on actual performance. The values for Messrs. Sinclair and Fink reflect the allocated portion of their actual bonuses awarded under the annual incentive plan. For additional discussion of this program, read
Compensation Discussion and Analysis — Analysis of
2016
Compensation Actions — Performance-Based Annual Cash Incentives (Bonuses)
of Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
March 31, 2017
. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(3)
|
Reflects the in-the-money value of unvested stock options (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,
2016
. 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 10, 2016, 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, 2016. 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. All values reflect each named executive officer’s allocation percentage in effect as of December 31,
2016
.
|
(4)
|
Messrs. Sinclair’s and Fink’s values represent 24 months of health and welfare benefit coverage. These amounts are present values determined in accordance with GAAP. These values reflect their allocation percentage in effect as of December 31,
2016
. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Cash Severance
(1)
|
$
|
2,218,500
|
|
|
$
|
1,314,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Pro-rata Bonus
(2)
|
371,250
|
|
|
297,000
|
|
|
—
|
|
|
—
|
|
||||
Accelerated Anadarko Equity Awards
(3)
|
6,390,057
|
|
|
4,992,249
|
|
|
—
|
|
|
211,630
|
|
||||
Supplemental Pension Benefits
(4)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Nonqualified Deferred Compensation
(5)
|
227,650
|
|
|
130,413
|
|
|
—
|
|
|
—
|
|
||||
Health and Welfare Benefits
(6)
|
142,189
|
|
|
58,748
|
|
|
—
|
|
|
—
|
|
||||
Total
|
$
|
9,349,646
|
|
|
$
|
6,792,410
|
|
|
$
|
—
|
|
|
$
|
211,630
|
|
(1)
|
Mr. Sinclair’s values and Mr. Fink’s values assume 2.9 times and two times, respectively, the sum of base salary plus the highest bonus paid in the past three years and reflect their allocation percentages in effect as of December 31,
2016
, per the terms of their key employee change of control agreements with Anadarko. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(2)
|
Messrs. Sinclair’s and Fink’s values assume the full-year equivalent of their highest annual bonus allocated to us over the past three years. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(3)
|
Reflects the in-the-money value of unvested stock options, the value of unvested restricted stock shares and restricted stock units and the estimated current value of unvested performance units (based on performance to date) granted under Anadarko equity plans, all as of December 31,
2016
. Upon a Change of Control, the value of unvested performance units would be calculated based on Anadarko’s total shareholder return performance and stock price at the time of the Change of Control and converted into restricted stock units of the surviving company. In the event of an involuntary not for cause termination or voluntary for good reason termination within two years following a Change of Control, the units will generally be paid on the first business day that is at least six months and one day following the separation from service. In the event of an involuntary not for cause or voluntary for good reason termination that is more than two years following a Change of Control, the units will be paid at the end of the original performance period. All values reflect each named executive officer’s allocation percentage in effect as of December 31,
2016
.
|
(4)
|
Under the terms of their change of control agreements, Messrs. Sinclair and Fink would receive a special retirement benefit enhancement that is equivalent to the additional supplemental pension benefits that would have accrued under Anadarko’s retirement plan assuming they were eligible for subsidized early retirement benefits and include additional special pension credits. The value of this benefit has not been included in this table as Anadarko does not allocate expense to the Partnership for distribution of these benefits. If Anadarko were to allocate this expense to the Partnership, assuming their allocation percentages in effect as of December 31,
2016
, the expense would be as follows: Mr. Sinclair—$221,851 and Mr. Fink—$91,263.
|
(5)
|
Mr. Sinclair’s values and Mr. Fink’s values reflect an additional three years and two years, respectively, of employer contributions into the savings restoration plan at their current contribution rate to the Plan and are based on their allocation percentages in effect as of December 31,
2016
, per the terms of their key employee change of control agreements with Anadarko. No value has been disclosed for Mr. Peacock as he is not eligible for this additional benefit.
|
(6)
|
Mr. Sinclair’s values and Mr. Fink’s values represent 36 months and 24 months, respectively, of health and welfare benefit coverage. All amounts are present values determined in accordance with GAAP and reflect their allocation percentages in effect as of December 31,
2016
. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Cash Severance
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accelerated Anadarko Equity Awards
(1)
|
6,390,057
|
|
|
4,992,249
|
|
|
—
|
|
|
211,630
|
|
||||
Health and Welfare Benefits
(2)
|
103,631
|
|
|
160,317
|
|
|
—
|
|
|
58,396
|
|
||||
Total
|
$
|
6,493,688
|
|
|
$
|
5,152,566
|
|
|
$
|
—
|
|
|
$
|
270,026
|
|
(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,
2016
. In the event of a termination as a result of disability, performance units would be paid after the end of the applicable performance period, based on actual performance. All values reflect each named executive officer’s allocation percentage in effect as of December 31,
2016
.
|
(2)
|
Values reflect the continuation of additional death benefit coverage provided to certain employees of Anadarko until age 65. All amounts are present values determined in accordance with GAAP and reflect each named executive officer’s allocation percentage in effect as of December 31,
2016
.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Cash Severance
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accelerated Anadarko Equity Awards
(1)
|
6,390,057
|
|
|
4,992,249
|
|
|
—
|
|
|
211,630
|
|
||||
Life Insurance Proceeds
(2)
|
1,356,589
|
|
|
1,240,310
|
|
|
—
|
|
|
447,890
|
|
||||
Total
|
$
|
7,746,646
|
|
|
$
|
6,232,559
|
|
|
$
|
—
|
|
|
$
|
659,520
|
|
(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,
2016
. All values reflect each named executive officer’s allocation percentage in effect as of December 31,
2016
.
|
(2)
|
Values include amounts payable under additional death benefits provided to certain employees of Anadarko. These liabilities are not insured, but are self-funded by Anadarko. Proceeds are not exempt from federal taxes. Values shown include an additional tax gross-up amount to equate benefits with non-taxable life insurance proceeds. Values are based on each named executive officer’s allocation percentage in effect as of December 31,
2016
, and exclude death benefit proceeds from programs available to all employees.
|
•
|
an annual retainer of $90,000 for each board member;
|
•
|
an annual retainer of $2,000 for each member of the Audit Committee, or $22,000 for the Committee chair;
|
•
|
an annual retainer of $2,000 for each member of the Special Committee, or $22,000 for the Committee chair;
|
•
|
a fee of $2,000 for each board meeting attended;
|
•
|
a fee of $2,000 for each committee meeting attended; and
|
•
|
annual grants of phantom units with a value of approximately $90,000 on the date of grant, all of which vest 100% on the first anniversary of the date of grant (with vesting to be accelerated upon a change of control of our general partner or Anadarko). The non-employee directors received such a grant of phantom units on May 5,
2016
.
|
Name
|
|
Fees Earned or Paid in Cash
|
|
Stock Awards
(1)
|
|
Option Awards
|
|
Non-Equity Incentive Plan Compensation
|
|
All Other Compensation
|
|
Total
|
||||||||||||
Steven D. Arnold
|
|
$
|
124,000
|
|
|
$
|
90,022
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
214,022
|
|
Milton Carroll
|
|
128,000
|
|
|
90,022
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
218,022
|
|
||||||
James R. Crane
|
|
126,000
|
|
|
90,022
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
216,022
|
|
||||||
David J. Tudor
|
|
136,000
|
|
|
90,022
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
226,022
|
|
(1)
|
The amounts included in the Stock Awards column represent the grant date fair value of non-option awards made to directors in
2016
, 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,
2016
, each of the non-employee directors had
1,826
outstanding phantom units.
|
Name
|
|
Grant Date
|
|
Phantom Units (#)
|
|
Grant Date Fair Value of Stock and Option Awards ($)
(1)
|
||
Steven D. Arnold
|
|
May 5
|
|
1,826
|
|
|
90,022
|
|
Milton Carroll
|
|
May 5
|
|
1,826
|
|
|
90,022
|
|
James R. Crane
|
|
May 5
|
|
1,826
|
|
|
90,022
|
|
David J. Tudor
|
|
May 5
|
|
1,826
|
|
|
90,022
|
|
(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
2016
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
|
|
|
39.90%
|
|
178,587,365
|
|
|
81.55%
|
Robert G. Gwin
|
|
10,000
|
|
|
*
|
|
200,000
|
|
|
*
|
Donald R. Sinclair (through February 13, 2017)
|
|
80,664
|
|
|
*
|
|
161,754
|
|
|
*
|
Benjamin M. Fink
|
|
2,213
|
|
|
*
|
|
18,683
|
|
|
*
|
Craig W. Collins
|
|
480
|
|
|
*
|
|
400
|
|
|
*
|
Philip H. Peacock
|
|
—
|
|
|
*
|
|
7,500
|
|
|
*
|
Steven D. Arnold
(3)
|
|
34,317
|
|
|
*
|
|
7,500
|
|
|
*
|
Milton Carroll
(3) (4)
|
|
6,722
|
|
|
*
|
|
—
|
|
|
*
|
James R. Crane
(3)
|
|
9,501
|
|
|
*
|
|
—
|
|
|
*
|
Darrell E. Hollek
|
|
336
|
|
|
*
|
|
7,608
|
|
|
*
|
Robert K. Reeves
|
|
9,000
|
|
|
*
|
|
9,000
|
|
|
*
|
David J. Tudor
(3)
|
|
8,898
|
|
|
*
|
|
6,178
|
|
|
*
|
All directors and executive officers
as a group (11 persons)
|
|
162,131
|
|
|
*
|
|
418,623
|
|
|
*
|
*
|
Less than 1%
|
(1)
|
The address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380. No person listed owns any Series A Preferred units.
|
(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
12,537,100
Class C units of the Partnership.
|
(3)
|
Does not include
1,826
unvested phantom units that were granted to each of Messrs. Carroll, Crane, Tudor, and Arnold 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 WES units 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)
|
|
112,471
|
|
|
278,203
|
|
|
390,674
|
|
|
*
|
Donald R. Sinclair (through February 13, 2017)
(3)
|
|
22,712
|
|
|
66,357
|
|
|
89,069
|
|
|
*
|
Benjamin M. Fink
(3)
|
|
9,390
|
|
|
31,688
|
|
|
41,078
|
|
|
*
|
Craig W. Collins
(3) (4)
|
|
6,897
|
|
|
1,515
|
|
|
8,412
|
|
|
*
|
Philip H. Peacock
(4)
|
|
6,069
|
|
|
—
|
|
|
6,069
|
|
|
*
|
Steven D. Arnold
|
|
3,800
|
|
|
—
|
|
|
3,800
|
|
|
*
|
Milton Carroll
|
|
—
|
|
|
—
|
|
|
—
|
|
|
*
|
James R. Crane
|
|
—
|
|
|
—
|
|
|
—
|
|
|
*
|
Darrell E. Hollek
(3)
|
|
24,947
|
|
|
98,871
|
|
|
123,818
|
|
|
*
|
Robert K. Reeves
(3)
|
|
213,160
|
|
|
217,702
|
|
|
430,862
|
|
|
*
|
David J. Tudor
|
|
—
|
|
|
—
|
|
|
—
|
|
|
*
|
All directors and executive officers
as a group (11 persons)
(3)
|
|
399,446
|
|
|
694,336
|
|
|
1,093,782
|
|
|
*
|
*
|
Less than 1%
|
(1)
|
The address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380. No person listed owns any Series A Preferred units.
|
(2)
|
As of December 31, 2016, there were 559.0 million shares of Anadarko common stock issued and outstanding.
|
(3)
|
Does not include unvested restricted stock units of Anadarko held by the following individuals in the amounts indicated: Robert G. Gwin—32,833; Donald R. Sinclair—31,100; Benjamin M. Fink—25,016; Craig W. Collins—3,669; Darrell E. Hollek—29,552; and Robert K. Reeves—25,615; for a total of 147,785 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 6,069 and 6,897 unvested shares of restricted common stock of Anadarko held by Philip H. Peacock and Craig W. Collins, 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
|
|
Tortoise Capital Advisors, L.L.C.
11550 Ash Street
Suite 300
Leawood, KS 66211
|
|
12,307,332
(1)
|
|
9.40%
|
Common Units
|
|
Kayne Anderson Capital Advisors, L.P.
1800 Avenue of the Stars Third Floor Los Angeles, CA 90067 |
|
7,326,224
(2)
|
|
5.61%
|
(1)
|
Based upon its Schedule 13G/A filed February 13,
2017
, with the SEC with respect to Partnership securities held as of December 31,
2016
, Tortoise Capital Advisors, L.L.C. has shared voting power as to 11,046,458 common units and shared dispositive power as to 12,150,844 common units.
|
(2)
|
Based upon its Schedule 13G/A filed January 25,
2017
, with the SEC with respect to Partnership securities held as of December 31,
2016
, Kayne Anderson Capital Advisors, L.P. has shared voting and dispositive power as to 7,326,224 common units.
|
Plan Category
|
|
(a)
Number of
Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights
|
|
(b)
Weighted-Average
Exercise Price of
Outstanding
Options, Warrants
and Rights
|
|
(c)
Number of Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
(Excluding Securities
Reflected in Column(a))
|
|||
Equity compensation plans approved by security holders
|
|
—
|
|
|
—
|
|
|
—
|
|
Equity compensation plans not approved by security holders
(1)
|
|
7,304
|
|
|
—
(2)
|
|
|
2,120,711
|
|
Total
|
|
7,304
|
|
|
—
|
|
|
2,120,711
|
|
(1)
|
The Board of Directors adopted the WES LTIP in connection with the IPO of our common units.
|
(2)
|
Phantom units constitute the only rights outstanding under the WES LTIP. Each phantom unit that may be settled in common units entitles the holder to receive, upon vesting, one common unit with respect to each phantom unit, without payment of any cash. Accordingly, there is no reportable weighted-average exercise price.
|
Formation stage
|
|
|
|
|
|
The consideration received by Anadarko for the contribution of the assets and liabilities to us
|
|
5,725,431 common units; 26,536,306 subordinated units; 1,083,115 general partner units, and our IDRs.
|
|
|
|
Operational stage
|
|
|
|
|
|
Distributions of available cash to our general partner, WGP and other subsidiaries of Anadarko
|
|
We will generally make cash distributions 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, 2016, 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 21, 2017,
we have issued 1,623,247 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
2016
); 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, 2016 |
||
Reimbursement of general and administrative expenses
|
|
$
|
29,360
|
|
Reimbursement of public company expenses
|
|
8,410
|
|
|
Total reimbursement
|
|
$
|
37,770
|
|
•
|
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,
|
||||||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||
thousands
|
|
Purchases
|
|
Sales
|
||||||||||||||||||||
Cash consideration
|
|
$
|
3,965
|
|
|
$
|
10,903
|
|
|
$
|
22,943
|
|
|
$
|
623
|
|
|
$
|
925
|
|
|
$
|
402
|
|
Net carrying value
|
|
(3,366
|
)
|
|
(6,318
|
)
|
|
(12,210
|
)
|
|
(605
|
)
|
|
(972
|
)
|
|
(375
|
)
|
||||||
Partners’ capital adjustment
|
|
$
|
599
|
|
|
$
|
4,585
|
|
|
$
|
10,733
|
|
|
$
|
18
|
|
|
$
|
(47
|
)
|
|
$
|
27
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues and other
(1)
|
|
$
|
1,228,232
|
|
|
$
|
1,220,639
|
|
|
$
|
1,203,974
|
|
Equity income, net – affiliates
(1)
|
|
78,717
|
|
|
71,251
|
|
|
57,836
|
|
|||
Cost of product
(1)
|
|
80,455
|
|
|
167,354
|
|
|
127,930
|
|
|||
Operation and maintenance
(2)
|
|
72,330
|
|
|
77,061
|
|
|
71,386
|
|
|||
General and administrative
(3)
|
|
38,066
|
|
|
33,903
|
|
|
31,308
|
|
|||
Operating expenses
|
|
190,851
|
|
|
278,318
|
|
|
230,624
|
|
|||
Interest income
(4)
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
(5)
|
|
(7,747
|
)
|
|
14,398
|
|
|
—
|
|
|||
Proceeds from the issuance of common units, net of offering expenses
(6)
|
|
25,000
|
|
|
—
|
|
|
—
|
|
|||
Distributions to unitholders
(7)
|
|
382,711
|
|
|
314,200
|
|
|
234,024
|
|
|||
Above-market component of swap extensions with Anadarko
(8)
|
|
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 the acquisition of our assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of our assets by us. These amounts include equity-based compensation expense allocated to us by Anadarko 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)
|
For the years ended December 31, 2016 and 2015, 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 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
.
|
(7)
|
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.
|
(8)
|
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
|
|
2016
|
|
2015
|
||||
Audit fees
|
|
$
|
1,020
|
|
|
$
|
1,309
|
|
Audit-related fees
|
|
690
|
|
|
423
|
|
||
Total
|
|
$
|
1,710
|
|
|
$
|
1,732
|
|
Exhibit
Number
|
|
Description
|
2.1#
|
|
Contribution, Conveyance and Assumption Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, Anadarko Petroleum Corporation, WGR Holdings, LLC, Western Gas Resources, Inc., WGR Asset Holding Company LLC, Western Gas Operating, LLC and WGR Operating, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
2.2#
|
|
Contribution Agreement, dated as of November 11, 2008, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on November 13, 2008, File No. 001-34046).
|
2.3#
|
|
Contribution Agreement, dated as of July 10, 2009, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, Anadarko Uintah Midstream, LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
|
2.4#
|
|
Contribution Agreement, dated as of January 29, 2010 by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, Mountain Gas Resources LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010 File No. 001-34046).
|
2.5#
|
|
Contribution Agreement, dated as of July 30, 2010, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046).
|
2.6#
|
|
Purchase and Sale Agreement, dated as of January 14, 2011, by and among Western Gas Partners, LP, Kerr-McGee Gathering LLC and Encana Oil & Gas (USA) Inc. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 18, 2011 File No. 001-34046).
|
2.7#
|
|
Contribution Agreement, dated as of December 15, 2011, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 15, 2011, File No. 001-34046).
|
Exhibit
Number
|
|
Description
|
2.8#
|
|
Contribution Agreement, dated as of February 27, 2013, by and among Anadarko Marcellus Midstream, L.L.C., Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP, Anadarko Petroleum Corporation and Anadarko E&P Onshore LLC (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
|
2.9#
|
|
Contribution Agreement, dated as of February 27, 2014, by and among WGR Asset Holding Company LLC, APC Midstream Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 2.9 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 28, 2014, File No. 001-34046).
|
2.10#
|
|
Agreement and Plan of Merger, dated October 28, 2014, by and among Western Gas Partners, LP, Maguire Midstream LLC and Nuevo Midstream, LLC (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on October 28, 2014, File No. 001-34046).
|
2.11#
|
|
Purchase and Sale Agreement, dated as of March 2, 2015, by and among WGR Asset Holding Company LLC, Delaware Basin Midstream, LLC, Western Gas Partners, LP, and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 3, 2015, File No. 001-34046).
|
2.12#
|
|
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 (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 1, 2016, File No.001-34046).
|
3.1
|
|
Certificate of Limited Partnership of Western Gas Partners, LP (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
|
3.2
|
|
Second Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 14, 2016 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 16, 2016, File No. 001-34046).
|
3.3
|
|
Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 14, 2016 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 16, 2016, File No. 001-34046).
|
3.4*
|
|
Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated February 22, 2017.
|
3.5
|
|
Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
|
3.6
|
|
Second Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated December 12, 2012 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-34046).
|
4.1
|
|
Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
|
4.2
|
|
Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
|
4.3
|
|
First Supplemental Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
|
4.4
|
|
Form of 5.375% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
|
4.5
|
|
Fourth Supplemental Indenture, dated as of June 28, 2012, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
|
4.6
|
|
Form of 4.000% Senior Notes due 2022 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
|
Exhibit
Number
|
|
Description
|
4.7
|
|
Fifth Supplemental Indenture, dated as of August 14, 2013, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 14, 2013, File No. 001-34046).
|
4.8
|
|
Form of 2.600% Senior Notes due 2018 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 14, 2013, File No. 001-34046).
|
4.9
|
|
Sixth Supplemental Indenture, dated as of March 20, 2014, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
|
4.10
|
|
Form of 5.450% Senior Notes due 2044 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
|
4.11
|
|
Seventh Supplemental Indenture, dated as of June 4, 2015, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).
|
4.12
|
|
Form of 3.950% Senior Notes due 2025 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).
|
4.13
|
|
Eighth Supplemental Indenture, dated as of July 12, 2016, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046).
|
4.14
|
|
Form of 4.650% Senior Notes due 2026 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046).
|
4.15
|
|
Registration Rights Agreement by and between Western Gas Partners, LP and the Purchasers party thereto, dated as of March 14, 2016, (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 16, 2016, File No. 001-34046).
|
4.16*
|
|
Consent and Conversion Agreement, dated February 22, 2017, by and among the Partnership and the holders of the outstanding Series A Preferred Units party thereto.
|
10.1
|
|
Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC and Anadarko Petroleum Corporation, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.2
|
|
Amendment No. 1 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of December 19, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 24, 2008, File No. 001-34046).
|
10.3
|
|
Amendment No. 2 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of July 22, 2009 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
|
10.4
|
|
Amendment No. 3 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of December 31, 2009 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 7, 2010, File No. 001-34046).
|
10.5
|
|
Amendment No. 4 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of January 29, 2010 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010, File No. 001-34046).
|
10.6
|
|
Amendment No. 5 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of August 2, 2010 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046).
|
10.7
|
|
Services And Secondment Agreement between Western Gas Holdings, LLC and Anadarko Petroleum Corporation dated May 14, 2008 (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.8
|
|
Amendment No. 1 to Services And Secondment Agreement between Western Gas Holdings, LLC and Anadarko Petroleum Corporation dated December 10, 2015 (incorporated by reference to Exhibit 10.8 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 25, 2016, File No. 001-34046).
|
Exhibit
Number
|
|
Description
|
10.9
|
|
Tax Sharing Agreement by and among Anadarko Petroleum Corporation and Western Gas Partners, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.5 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.10
|
|
Anadarko Petroleum Corporation Fixed Rate Note due 2038 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.11
|
|
Form of Commodity Price Swap Agreement (
incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on May 6, 2010, File No. 001-34046
).
|
10.12‡
|
|
Form of Indemnification Agreement by and between Western Gas Holdings, LLC, its Officers and Directors (incorporated by reference to Exhibit 10.10 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
|
10.13‡
|
|
Western Gas Partners, LP 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.13 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
|
10.14‡
|
|
Form of Award Agreement under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.9 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.15†
|
|
Amended and Restated Limited Liability Company Agreement of Chipeta Processing LLC effective July 23, 2009 (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on November 12, 2009, File No. 001-34046).
|
10.16
|
|
Second Amended and Restated Revolving Credit Agreement, dated as of February 26, 2014, among Western Gas Partners, LP, Wells Fargo Bank National Association, as the administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.15 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 28, 2014, File No. 001-34046).
|
10.17*
|
|
First Amendment to Second Amended and Restated Revolving Credit Agreement, dated as of December 16, 2016, among Western Gas Partners, LP Wells Fargo Bank, National Association, as administrative agent and the lenders party thereto.
|
10.18
|
|
Second Amendment to Second Amended and Restated Revolving Credit Agreement, dated as of December 16, 2016, among Western Gas Partners, LP Wells Fargo Bank, National Association, as administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 16, 2016, File No. 001-34046).
|
10.19*
|
|
Fourth Amended and Restated Indemnification Agreement, dated March 14, 2016, between Western Gas Holdings, LLC and Western Gas Resources, Inc.
|
10.20
|
|
AMH Indemnification Agreement, dated March 3, 2014, between Western Gas Holdings, LLC and APC Midstream Holdings, LLC (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2014, File No. 001-34046).
|
10.21*
|
|
KWC Indemnification Agreement, dated March 14, 2016, between Western Gas Holdings, LLC and Kerr-McGee Worldwide Corporation.
|
10.22
|
|
Unit Purchase Agreement, dated October 28, 2014, by and among Western Gas Partners, LP, APC Midstream Holdings, LLC and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on October 28, 2014, File No. 001-34046).
|
10.23†
|
|
Gas Gathering Agreement effective July 1, 2010 between Kerr-McGee Gathering LLC and Kerr-McGee Oil & Gas Onshore LP, as amended by Amendment No. 1 dated August 4, 2011, Amendment No. 2 dated December 3, 2012, Amendment No. 3 dated November 19, 2013 and Amendment No. 4 dated June 2, 2014 (incorporated by reference to Exhibit 10.23 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 26, 2015, File No. 001-34046).
|
10.24
|
|
Board Observation Agreement, dated March 14, 2016, among Western Gas Partners, LP, Western Gas Holdings, LLC, Western Gas Equity Partners, LP and the persons set forth on Schedule A thereto (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 16, 2016, File No. 001-34046).
|
Exhibit
Number
|
|
Description
|
12.1*
|
|
Ratio of Earnings to Fixed Charges.
|
21.1*
|
|
List of Subsidiaries of Western Gas Partners, LP.
|
23.1*
|
|
Consent of KPMG LLP.
|
31.1*
|
|
Certification of Chief Executive Officer and Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
32.1**
|
|
Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
101.INS*
|
|
XBRL Instance Document
|
101.SCH*
|
|
XBRL Schema Document
|
101.CAL*
|
|
XBRL Calculation Linkbase Document
|
101.DEF*
|
|
XBRL Definition Linkbase Document
|
101.LAB*
|
|
XBRL Label Linkbase Document
|
101.PRE*
|
|
XBRL Presentation Linkbase Document
|
*
|
Filed herewith
|
**
|
Furnished herewith
|
#
|
Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.
|
†
|
Portions of this exhibit, which was previously filed with the Securities and Exchange Commission, were omitted pursuant to a request for confidential treatment. The omitted portions were filed separately with the Securities and Exchange Commission.
|
‡
|
Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.
|
|
WESTERN GAS PARTNERS, LP
|
|
|
February 23, 2017
|
|
|
|
|
/s/ Benjamin M. Fink
|
|
Benjamin M. Fink
President, Chief Executive Officer,
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, Chief Financial Officer and Treasurer
|
Benjamin M. Fink
|
(Principal Executive, Financial and Accounting Officer)
|
|
|
/s/ Darrell E. Hollek
|
Director
|
Darrell E. Hollek
|
|
|
|
/s/ Robert K. Reeves
|
Director
|
Robert K. Reeves
|
|
|
|
/s/ Steven D. Arnold
|
Director
|
Steven D. Arnold
|
|
|
|
/s/ Milton Carroll
|
Director
|
Milton Carroll
|
|
|
|
|
Director
|
James R. Crane
|
|
|
|
/s/ David J. Tudor
|
Director
|
David J. Tudor
|
|
|
GENERAL PARTNER:
|
|
|
|
|
|
Western Gas Holdings, LLC
|
|
|
|
|
|
By:
|
/s/ Benjamin M. Fink
|
|
Name:
|
Benjamin M. Fink
|
|
Title:
|
President, Chief Executive Officer,
Chief Financial Officer and Treasurer
|
|
WESTERN GAS PARTNERS, LP
|
||
|
|
|
|
|
By:
|
Western Gas Holdings, LLC, its general partner
|
|
|
|
|
|
|
|
By:
|
/s/ Benjamin M. Fink
|
|
|
Name:
|
Benjamin M. Fink
|
|
|
Title:
|
President, Chief Executive Officer,
Chief Financial Officer and Treasurer
|
|
KA WESTERN GAS HOLDINGS LLC
|
||
|
|
|
|
|
By:
|
KA Fund Advisors, LLC, as Manager
|
|
|
|
|
|
|
|
By:
|
/s/ James C. Baker
|
|
|
Name:
|
James C. Baker
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
KAISER PERMANENTE GROUP TRUST
|
||
|
|
|
|
|
By:
|
Kayne Anderson Capital Advisors, L.P., as its Manager
|
|
|
|
|
|
|
|
By:
|
/s/ David Shladovsky
|
|
|
Name:
|
David Shladovsky
|
|
|
Title:
|
General Counsel
|
|
|
|
|
|
KAYNE ANDERSON MIDSTREAM INSTITUTIONAL FUND, L.P.
|
||
|
|
|
|
|
By:
|
Kayne Anderson Capital Advisors, L.P., as its General Partner
|
|
|
|
|
|
|
|
By:
|
/s/ David Shladovsky
|
|
|
Name:
|
David Shladovsky
|
|
|
Title:
|
General Counsel
|
|
|
|
|
|
KAYNE ANDERSON MLP FUND, L.P.
|
||
|
|
|
|
|
By:
|
Kayne Anderson Capital Advisors, L.P., as its General Partner
|
|
|
|
|
|
|
|
By:
|
/s/ David Shladovsky
|
|
|
Name:
|
David Shladovsky
|
|
|
Title:
|
General Counsel
|
|
KANTI (QP), L.P.
|
||
|
|
|
|
|
By:
|
Kayne Anderson Capital Advisors, L.P., as its General Partner
|
|
|
|
|
|
|
|
By:
|
/s/ David Shladovsky
|
|
|
Name:
|
David Shladovsky
|
|
|
Title:
|
General Counsel
|
|
|
|
|
|
MASSACHUSETTS MUTUAL LIFE INSURANCE COMPANY
|
||
|
|
|
|
|
By:
|
KA Fund Advisors, LLC, as Manager
|
|
|
|
|
|
|
|
By:
|
/s/ James C. Baker
|
|
|
Name:
|
James C. Baker
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
BELFER CAPITAL PARTNERS LP
|
||
|
|
|
|
|
By:
|
KA Fund Advisors, LLC, as its Manager
|
|
|
|
|
|
|
|
By:
|
/s/ James C. Baker
|
|
|
Name:
|
James C. Baker
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
ORANGE COUNTY EMPLOYEES RETIREMENT SYSTEM
|
||
|
|
|
|
|
By:
|
Kayne Anderson Capital Advisors, L.P., as its Manager
|
|
|
|
|
|
|
|
By:
|
/s/ David Shladovsky
|
|
|
Name:
|
David Shladovsky
|
|
|
Title:
|
General Counsel
|
|
|
|
|
|
KAYNE PREFERRED FUND LLC
|
||
|
|
|
|
|
|
By:
|
/s/ James C. Baker
|
|
|
Name:
|
James C. Baker
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
KAYNE ANDERSON NON-TRADITIONAL INVESTMENTS, L.P.
|
||
|
|
|
|
|
By:
|
Kayne Anderson Capital Advisors, L.P., as its General Partner
|
|
|
|
|
|
|
|
By:
|
/s/ David Shladovsky
|
|
|
Name:
|
David Shladovsky
|
|
|
Title:
|
General Counsel
|
|
|
|
|
|
KAYNE ANDERSON MLP INVESTMENT COMPANY
|
||
|
|
|
|
|
By:
|
KA Fund Advisors, LLC, as its Manager
|
|
|
|
|
|
|
|
By:
|
/s/ James C. Baker
|
|
|
Name:
|
James C. Baker
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
KAYNE ANDERSON ENERGY DEVELOPMENT COMPANY
|
||
|
|
|
|
|
By:
|
KA Fund Advisors, LLC, as its Manager
|
|
|
|
|
|
|
|
By:
|
/s/ James C. Baker
|
|
|
Name:
|
James C. Baker
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
KAYNE SELECT MIDSTREAM RECOVERY FUND, L.P.
|
||
|
|
|
|
|
By:
|
Kayne Anderson Capital Advisors, L.P., as its General Partner
|
|
|
|
|
|
|
|
By:
|
/s/ David Shladovsky
|
|
|
Name:
|
David Shladovsky
|
|
|
Title:
|
General Counsel
|
|
|
|
|
|
BELFER CORP.
|
||
|
|
|
|
|
By:
|
KA Fund Advisors, LLC, as its Manager
|
|
|
|
|
|
|
|
By:
|
/s/ James C. Baker
|
|
|
Name:
|
James C. Baker
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
ELIZABETH K. BELFER
|
||
|
|
|
|
|
By:
|
KA Fund Advisors, LLC, as Manager
|
|
|
|
|
|
|
|
By:
|
/s/ James C. Baker
|
|
|
Name:
|
James C. Baker
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
LAURENCE D. BELFER
|
||
|
|
|
|
|
By:
|
KA Fund Advisors, LLC, as Manager
|
|
|
|
|
|
|
|
By:
|
/s/ James C. Baker
|
|
|
Name:
|
James C. Baker
|
|
|
Title:
|
Managing Director
|
|
FR XIII WES HOLDINGS LLC
|
||
|
|
|
|
|
|
By:
|
/s/ Gary Reaves
|
|
|
Name:
|
Gary Reaves
|
|
|
Title:
|
Authorized Person
|
|
|
|
|
|
FR WES CO-INVESTMENT, L.P.
|
||
|
|
|
|
|
|
By:
|
/s/ Gary Reaves
|
|
|
Name:
|
Gary Reaves
|
|
|
Title:
|
Authorized Person
|
Holder
|
|
Series A Preferred
Units to be
Converted on the
First Conversion
Date
|
|
Series A Preferred
Units to be
Converted on the
Second Conversion
Date
|
||
KA Western Gas Holdings LLC
1800 Avenue of the Stars, 3
rd
Floor
Los Angeles, CA 90067
Attn: David Shladovsky
Email: dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
1,343,590
|
|
|
1,343,591
|
|
|
|
|
|
|
||
Kaiser Permanente Group Trust
1800 Avenue of the Stars, 3
rd
Floor
Los Angeles, CA 90067
Attn: David Shladovsky
Email: dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
797,194
|
|
|
797,194
|
|
|
|
|
|
|
||
Kayne Anderson Midstream Institutional Fund, L.P.
1800 Avenue of the Stars, 3
rd
Floor
Los Angeles, CA 90067
Attn: David Shladovsky
Email: dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
355,000
|
|
|
355,000
|
|
|
|
|
|
|
||
Kayne Anderson MLP Fund, L.P.
1800 Avenue of the Stars, 3
rd
Floor
Los Angeles, CA 90067
Attn: David Shladovsky
Email: dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
355,000
|
|
|
355,000
|
|
|
|
|
|
|
||
KANTI (QP), L.P.
1800 Avenue of the Stars, 3
rd
Floor
Los Angeles, CA 90067
Attn: David Shladovsky
Email: dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
260,570
|
|
|
260,570
|
|
Massachusetts Mutual Life Insurance Company
1800 Avenue of the Stars, 3
rd
Floor
Los Angeles, CA 90067
Attn: David Shladovsky
Email: dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
199,298
|
|
|
199,299
|
|
|
|
|
|
|
||
Belfer Capital Partners LP
1800 Avenue of the Stars, 3
rd
Floor
Los Angeles, CA 90067
Attn: David Shladovsky
Email: dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
159,439
|
|
|
159,439
|
|
|
|
|
|
|
||
Orange County Employees Retirement System
1800 Avenue of the Stars, 3
rd
Floor
Los Angeles, CA 90067
Attn: David Shladovsky
Email: dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
159,439
|
|
|
159,439
|
|
|
|
|
|
|
||
Kayne Preferred Fund LLC
1800 Avenue of the Stars, 3
rd
Floor
Los Angeles, CA 90067
Attn: David Shladovsky
Email: dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
135,610
|
|
|
135,611
|
|
|
|
|
|
|
||
Kayne Anderson Non-Traditional Investments, L.P.
1800 Avenue of the Stars, 3
rd
Floor
Los Angeles, CA 90067
Attn: David Shladovsky
Email: dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
94,430
|
|
|
94,430
|
|
|
|
|
|
|
||
Kayne Anderson MLP Investment Company
1800 Avenue of the Stars, 3
rd
Floor
Los Angeles, CA 90067
Attn: David Shladovsky
Email: dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
67,185
|
|
|
67,185
|
|
Kayne Anderson Energy Development Company
1800 Avenue of the Stars, 3
rd
Floor
Los Angeles, CA 90067
Attn: David Shladovsky
Email: dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
67,185
|
|
|
67,184
|
|
|
|
|
|
|
||
Kayne Select Midstream Recovery Fund, L.P.
1800 Avenue of the Stars, 3
rd
Floor
Los Angeles, CA 90067
Attn: David Shladovsky
Email: dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
39,860
|
|
|
39,859
|
|
|
|
|
|
|
||
Belfer Corp.
c/o Belfer Management LLC
767 Fifth Avenue, 46
th
Floor
New York, NY 10153
reporting@belfermgmt.com
dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
39,860
|
|
|
39,859
|
|
|
|
|
|
|
||
Elizabeth K. Belfer
c/o Belfer Management LLC
767 Fifth Avenue, 46
th
Floor
New York, NY 10153
reporting@belfermgmt.com
dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
15,944
|
|
|
15,944
|
|
|
|
|
|
|
||
Laurence D. Belfer
c/o Belfer Management LLC
767 Fifth Avenue, 46
th
Floor
New York, NY 10153
reporting@belfermgmt.com
dshladovsky@kaynecapital.com
jbaker@kaynecapital.com
|
|
15,944
|
|
|
15,944
|
|
|
|
|
|
|
||
Total Kayne Anderson
|
|
4,105,548
|
|
|
4,105,548
|
|
|
|
|
|
|
FR XIII WES Holdings LLC
600 Travis, Suite 6000
Houston, TX 77002
Attn: Gary Reaves
Email: greaves@firstreserve.com
|
|
4,512,117
|
|
|
4,512,118
|
|
|
|
|
|
|
||
FR WES Co-Investment, L.P.
600 Travis, Suite 6000
Houston, TX 77002
Attn: Gary Reaves
Email: greaves@firstreserve.com
|
|
2,343,750
|
|
|
2,343,750
|
|
|
|
|
|
|
||
Total First Reserve
|
|
6,855,867
|
|
|
6,855,868
|
|
|
|
|
|
|
||
TOTAL
|
|
10,961,415
|
|
|
10,961,416
|
|
Holder
|
|
Broker Information
|
KA Western Gas Holdings LLC
|
|
DTC Number: 0226
Firm Name: National Financial Services
Account Name: KA Western Gas Holdings LLC
Account #: K8H-002086
Tax ID #: 35-2554749
|
|
|
|
Kaiser Permanente Group Trust
|
|
DTC Number: 0997
Firm Name: State Street Bank and Trust Company
Account Name: Kaiser Permanente Group Trust
Account #: 11QI
Tax ID #: 94-6365467
|
|
|
|
Kayne Anderson Midstream Institutional Fund, L.P.
|
|
DTC Number: 0352
Firm Name: J.P. Morgan
Account Name: Kayne Anderson Midstream Institutional Fund, L.P.
Account #: 102-38790
Tax ID #: 26-3885960
|
|
|
|
Kayne Anderson MLP Fund, L.P.
|
|
DTC Number: 0352
Firm Name: J.P. Morgan
Account Name: Kayne Anderson MLP Fund, L.P.
Account #: 102-35700
Tax ID #: 61-1437017
|
|
|
|
KANTI (QP), L.P.
|
|
DTC Number: 0352
Firm Name: J.P. Morgan
Account Name: KANTI (QP), L.P.
Account #: 102-45032
Tax ID #: 46-2290393
|
|
|
|
Massachusetts Mutual Life Insurance Company
|
|
DTC Number: 0997
Firm Name: State Street Bank and Trust Company
Account Name: Massachusetts Mutual Life Insurance Company
Account #: IEG7
Tax ID #: 04-1590850
|
|
|
|
Belfer Capital Partners LP
|
|
JPMorgan Chase Bank, N.A.
DTC Participant Number - 902
Credit Account Number - P72500
FFC Acct Number - PBD # 51 29260 001
FFC Acct Name - Belfer Capital Partners, LP
Contact - James Pretti @ 1-888-207-2025
|
|
|
|
Orange County Employees Retirement System
|
|
DTC Number: 0997
Firm Name: State Street Bank and Trust Company
Account Name: Orange County Employees Retirement System
Account #: JV9N
Tax ID #: 04-3384940
|
|
|
|
Kayne Preferred Fund LLC
|
|
DTC Number: 0226
Firm Name: National Financial Services
Account Name: Kayne Preferred Fund LLC
Account #: K8H-002084
Tax ID #: 35-2553835
|
|
|
|
Kayne Anderson Non-Traditional Investments, L.P.
|
|
DTC Number: 0352
Firm Name: J.P. Morgan
Account Name: Kayne Anderson Non-Traditional Investments, L.P.
Account #: 102-36274
Tax ID #: 95-4198602
|
|
|
|
Kayne Anderson MLP Investment Company
|
|
DTC Number: 0352
Firm Name: J.P. Morgan
Account Name: Kayne Anderson MLP Investment Company Account #: 102-39488
Tax ID #: 56-2474626
|
|
|
|
Kayne Anderson Energy Development Company
|
|
DTC Number: 0352
Firm Name: J.P. Morgan
Account Name: Kayne Anderson Energy Development Company
Account #: 102-39490
Tax ID #: 20-4991752
|
|
|
|
Kayne Select Midstream Recovery Fund, L.P.
|
|
DTC Number: 2424
Firm Name: J.P. Morgan
Account Name: Kayne Select Midstream Recovery Fund, L.P.
Account #: 113-80158
Tax ID #: 47-5195808
|
|
|
|
Belfer Corp.
|
|
JPMorgan Chase Bank, N.A.
DTC Participant Number - 902
Credit Account Number - P72500
FFC Acct Number - PBD # 26 63486 007
FFC Acct Name - Belfer Corp
Contact - James Pretti @ 1-888-207-2025
|
|
|
|
Elizabeth K. Belfer
|
|
JPMorgan Chase Bank, N.A.
DTC Participant Number - 902
Credit Account Number - P72500
FFC Acct Number - PBD # 26 76530 007
FFC Acct Name - Elizabeth K. Belfer
Contact - James Pretti @ 1-888-207-2025
|
|
|
|
Laurence D. Belfer
|
|
JPMorgan Chase Bank, N.A.
DTC Participant Number - 902
Credit Account Number - P72500
FFC Acct Number - PBD # 26 65040 000
FFC Acct Name - Laurence D. Belfer
Contact - James Pretti @ 1-888-207-2025
|
|
|
|
FR XIII WES Holdings LLC
|
|
DTC Number: 0226
Firm Name: National Financial Services
Account Name: FR XIII WES Holdings LLC
Account #: K8H-002087
Tax ID #: 81-1540408
|
|
|
|
FR WES Co-Investment, L.P.
|
|
DTC Number: 0226
Firm Name: National Financial Services
Account Name: FR WES Co-Investment, L.P.
Account #: K8H-02088
Tax ID #: 81-1899621
|
|
|
|
BORROWER
:
|
WESTERN GAS PARTNERS, LP
|
|
|
|
|
|
By:
|
Western Gas Holdings, LLC, its general partner
|
|
|
|
|
By:
|
/s/ Benjamin M. Fink
|
|
Name:
|
Benjamin M. Fink
|
|
Title:
|
Senior Vice President, Chief Financial Officer and Treasurer
|
ADMINISTRATIVE AGENT
:
|
WELLS FARGO BANK, NATIONAL ASSOCIATION
|
|
|
|
|
|
By:
|
/s/ Borden Tennant
|
|
Name:
|
Borden Tennant
|
|
Title:
|
Assistant Vice President
|
LENDERS
:
|
WELLS FARGO BANK, NATIONAL ASSOCIATION
|
|
|
|
|
|
By:
|
/s/ Borden Tennant
|
|
Name:
|
Borden Tennant
|
|
Title:
|
Assistant Vice President
|
|
THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.
|
|
|
|
|
|
By:
|
/s/ Sherwin Brandford
|
|
Name:
|
Sherwin Brandford
|
|
Title:
|
Director
|
|
U.S. BANK NATIONAL ASSOCIATION
|
|
|
|
|
|
By:
|
/s/ John Prigge
|
|
Name:
|
John Prigge
|
|
Title:
|
Vice President
|
|
DNB CAPITAL LLC
|
|
|
|
|
|
By:
|
/s/ Joe Hykle
|
|
Name:
|
Joe Hykle
|
|
Title:
|
Senior Vice President
|
|
|
|
|
By:
|
/s/ Robert Dupree
|
|
Name:
|
Robert Dupree
|
|
Title:
|
Senior Vice President
|
|
BARCLAYS BANK PLC
|
|
|
|
|
|
By:
|
/s/ Vanessa A. Kurbatskiy
|
|
Name:
|
Vanessa A. Kurbatskiy
|
|
Title:
|
Vice President
|
|
MORGAN STANLEY BANK, N.A.
|
|
|
|
|
|
By:
|
/s/ Dmitriy Barskiy
|
|
Name:
|
Dmitriy Barskiy
|
|
Title:
|
Authorized Signatory
|
|
ROYAL BANK OF CANADA
|
|
|
|
|
|
By:
|
/s/ Jay T. Sartain
|
|
Name:
|
Jay T. Sartain
|
|
Title:
|
Authorized Signatory
|
|
BANK OF MONTREAL
|
|
|
|
|
|
By:
|
/s/ Melissa Guzmann
|
|
Name:
|
Melissa Guzmann
|
|
Title:
|
Vice President
|
|
COMERICA BANK
|
|
|
|
|
|
By:
|
/s/ Chad Stephenson
|
|
Name:
|
Chad Stephenson
|
|
Title:
|
Senior Vice President
|
|
SOCIETE GENERALE
|
|
|
|
|
|
By:
|
/s/ Diego Medina
|
|
Name:
|
Diego Medina
|
|
Title:
|
Director
|
|
THE BANK OF NOVA SCOTIA
|
|
|
|
|
|
By:
|
/s/ Mark Sparrow
|
|
Name:
|
Mark Sparrow
|
|
Title:
|
Director
|
|
AMEGY BANK NATIONAL ASSOCIATION
|
|
|
|
|
|
By:
|
/s/ G. Scott Collins
|
|
Name:
|
G. Scott Collins
|
|
Title:
|
Senior Vice President
|
|
BRANCH BANKING AND TRUST COMPANY
|
|
|
|
|
|
By:
|
/s/ DeVon J. Lang
|
|
Name:
|
DeVon J. Lang
|
|
Title:
|
Senior Vice President
|
|
PNC BANK, NATIONAL ASSOCIATION
|
|
|
|
|
|
By:
|
/s/ Denise He
|
|
Name:
|
Denise He
|
|
Title:
|
Assistant Vice President
|
|
CAPITAL ONE, NATIONAL ASSOCIATION
|
|
|
|
|
|
By:
|
/s/ Matthew Molero
|
|
Name:
|
Matthew Molero
|
|
Title:
|
Senior Vice President
|
|
STIFEL BANK & TRUST
|
|
|
|
|
|
By:
|
/s/ Christian Jon Bugyis
|
|
Name:
|
Christian Jon Bugyis
|
|
Title:
|
Sr. Vice President
|
1.1
|
“
Excluded Claims
” means any and all amounts for which indemnification is provided pursuant to an Indemnification Agreement.
|
1.2
|
“
Indemnification Agreement
” means an Indemnification Agreement set forth on Schedule A hereto, as such Schedule A may be amended from time to time.
|
1.3
|
“
Lender Claim
” means any and all claims, damages, losses, liabilities, costs, or expenses whatsoever (including without limitation attorneys’ fees and expenses) which Indemnitee may incur (or which may be claimed against Indemnitee by any person or entity whatsoever), by reason of, or arising out of, any Proceeding against Borrower or Indemnitee in connection with the obligations of the Borrower under the Second Restated Credit Agreement and Indenture, other than Excluded Claims and only to the extent not satisfied by the assets of the Borrower.
|
1.4
|
“
Lender Claimant
” means the Administrative Agent, the Issuing Bank, a Syndication Agent, the Documentation Agent, the Swingline Lender, the Trustee, any Lender, any Holder, any Related Party of the foregoing, or any other Person that may assert a Lender Claim.
|
1.5
|
“
Proceeding
” means any threatened, pending or completed action, suit, claim, arbitration, alternate dispute resolution mechanism, investigation, inquiry, administrative hearing or any other actual, threatened or completed proceeding, whether made by or brought in the right of a Lender Claimant or otherwise, in which Indemnitee or Borrower was, is or will be involved as a party or otherwise.
|
1.6
|
Capitalized terms used and not otherwise defined herein shall have the meanings ascribed to such terms in the Second Restated Credit Agreement or the Indenture.
|
2.1
|
Indemnification by Indemnitor
. Subject to the limitations set forth in
Section 2.2
below, Indemnitor shall indemnify and hold harmless Indemnitee from and against any Lender Claim.
|
2.2
|
Conditions Precedent
. Notwithstanding anything contained in
Section 2.1
to the contrary, the Indemnitor shall not have any indemnification obligation under this Agreement unless Indemnitee has exhausted all of its remedies, if any, under the Partnership Agreement and under applicable law to collect from Borrower the amount of any Lender Claim;
provided
,
however
, that Indemnitee need not exhaust any remedies against Borrower to the extent Indemnitee reasonably determines that the expense anticipated to be incurred by Indemnitee in pursuing such claim against Borrower with respect to collection of the amount of the Lender Claim would exceed the anticipated recovery from Borrower with respect to such claim.
|
(a)
|
Notice of Lender Claim
. If any Lender Claimant notifies Indemnitee with respect to any Lender Claim, then Indemnitee will promptly give written notice to Indemnitor;
provided
,
however
, that no delay on the part of Indemnitee in notifying Indemnitor will relieve Indemnitee from any obligation under this
Section 2.3(a)
.
|
(b)
|
Assumption of Defense, etc
. Indemnitor will be entitled to participate in the defense of any Lender Claim that is the subject of a notice given by Indemnitee pursuant to
Section 2.3(a)
. In addition, Indemnitor will have the right to assume the defense of such Lender Claim with counsel of its choice reasonably satisfactory to Indemnitee so long as (i) Indemnitor gives written notice to Indemnitee within fifteen (15) days after Indemnitee has given notice of the Lender Claim that Indemnitor will indemnify Indemnitee from and against the entirety of the Lender Claim; (ii) Indemnitor provides Indemnitee with evidence reasonably acceptable to Indemnitee that Indemnitor will have adequate financial resources to defend against the Lender Claim and fulfill its indemnification obligations hereunder; (iii) Indemnitee has not been advised by counsel that an actual or potential conflict exists between Indemnitee and Indemnitor in connection with the defense of the Lender Claim; and (iv) settlement of an adverse judgment with respect to, or Indemnitor’s conduct of the defense of, the Lender Claim is not, in the good faith judgment of Indemnitee, likely to be adverse to Indemnitee’s reputation or continuing business interests. Indemnitee may retain separate co-counsel at its sole cost and expense and participate in the defense of the Lender Claim.
|
(c)
|
Limitations on Indemnitor
. Indemnitor will not consent to the entry of any judgment or enter into any compromise or settlement with respect to the Lender Claim without the prior written consent of Indemnitee unless such judgment, compromise or settlement (i) provides for the payment by Indemnitor of money as sole relief for the Lender Claimant and (ii) involves no finding or admission of any violation of law.
|
(d)
|
Indemnitee’s Control
. If Indemnitor does not deliver to Indemnitee the notice contemplated by
Section 2.3(b)
within fifteen (15) days after Indemnitee has given notice of the Lender Claim pursuant to
Section 2.3(a)
, or otherwise at any time fails to conduct the defense of the Lender Claim actively and diligently, Indemnitee may defend the Lender Claim in a good faith and reasonable manner, and may consent to the entry of any judgment or enter into any compromise or settlement with respect to the Lender Claim in any manner it may deem appropriate (and Indemnitee need not consult with, or obtain any consent from, Indemnitor in connection therewith).
|
2.4
|
Procedure for Notification
. Subject to
Section 2.3
, to obtain indemnification under this Agreement, Indemnitee shall submit to Indemnitor a written request, including therein or therewith such documentation and information as is reasonably available to Indemnitee and is reasonably necessary to determine whether and to what extent Indemnitee is entitled to indemnification under this Agreement. The delay or omission to notify Indemnitor will not relieve Indemnitor from any liability which it may have to Indemnitee otherwise than under this Agreement.
|
2.5
|
Presumption
. It shall be presumed that Indemnitee is entitled to indemnification under this Agreement if Indemnitee has submitted a request for indemnification in accordance with
Section 2.3(a)
, and Indemnitor shall, to the fullest extent not prohibited by law, have the burden of proof to overcome that presumption in connection with the making by any person, persons or entity of any determination contrary to that presumption.
|
2.6
|
Payment and Set-Off
. Indemnitor shall make any indemnification payment required under this Agreement promptly following request therefor (or, in the event that Indemnitor elects to participate in or assume the defense of a Lender Claim in accordance with this
Section 2
, promptly after any settlement or entry of any final judgment with respect to such Lender Claim), subject to Indemnitor’s right to rebut the presumption set forth in
Section 2.5
. Indemnitee may set off against any amounts that it must pay to Indemnitor under any agreement or instrument any amounts that Indemnitor must pay to Indemnitee under this Agreement.
|
3.1
|
Maintenance of Minimum Net Worth
. Indemnitor covenants and agrees with Indemnitee that it shall maintain at all times a net worth (determined without regard to Indemnitor’s limited partner interest in Borrower) of no less than the maximum amount of any Lender Claim for which Indemnitee could seek indemnification pursuant to
Section 2.1
hereof should an event described in
Section 1.1
hereof occur; provided that the amount of such potential Lender Claim shall be determined without regard to any assets of the Borrower that could be used to satisfy such potential Lender Claim.
|
3.2
|
Books and Records; Inspections and Audits
. Indemnitor shall keep, and will cause each of its Subsidiaries (if any) to keep, complete and accurate books and records of its transactions in accordance with good accounting practices on the basis of GAAP. Indemnitee may, upon thirty (30) days’ written notice to Indemnitor) (but in no event more than once each fiscal year), request that an audit of Indemnitor’s books and records be performed by be performed (at Indemnitee’s sole expense), in order to provide Indemnitee with such assurance as it deems reasonable and necessary with respect to Indemnitor’s financial condition.
|
Section 4
|
Waiver of Right to Subrogation.
In the event of any payment under this Agreement, Indemnitor expressly waives any right to subrogation with respect to any of the rights of recovery of Indemnitee or any Lender Claimant. Indemnitor also expressly waives any right to indemnification it may have under the Partnership Agreement with respect to any payment under this Agreement.
|
Section 5
|
Survival.
The provisions of this Agreement shall remain in full force and effect notwithstanding termination of the Second Restated Credit Agreement or Indenture,
|
Section 6
|
Severability.
If any term or provision of this Agreement shall be held to be illegal, invalid or unenforceable in any respect, then such term or provision shall be fully severable from this Agreement, this Agreement shall be construed and enforced as if such illegal, invalid or unenforceable term or provision had never been a part of this Agreement, and the remaining terms and provisions of this Agreement shall remain in full force and effect and shall not be affected by such illegal, invalid or unenforceable term or provision or by its severance from this Agreement.
|
Section 7
|
Entire Agreement.
This Agreement constitutes the entire agreement between the parties hereto pertaining to the subject matter hereof, and any and all other written or oral agreements relating to the subject matter hereof existing between the parties hereto are expressly cancelled. For the avoidance of doubt, nothing in this
Section 7
shall be deemed to invalidate any provision of the Partnership Agreement.
|
Section 8
|
Successors and Assigns.
Indemnitor agrees that all the rights, benefits and privileges herein and hereby conferred upon Indemnitee shall vest in, and be enforceable by, Indemnitee and its successors and assigns, and shall bind Indemnitor’s successors and assigns.
|
Section 9
|
Notices.
All notices, requests, demands and other communications under this Agreement shall be in writing and shall be deemed to have been duly given if (a) delivered by hand and receipted for by the party to whom said notice or other communication shall have been directed, (b) mailed by certified or registered mail with postage prepaid, on the third business day after the date on which it is so mailed, (c) mailed by reputable overnight courier and receipted for by the party to whom said notice or other communication shall have been directed or (d) sent by facsimile transmission, with receipt of oral confirmation that such transmission has been received:
|
a.
|
If to Indemnitee to:
|
b.
|
If to Indemnitor to:
|
Section 10
|
Counterparts.
This Agreement may be executed in counterparts, each of which shall be deemed to be an original, and all of which, taken together, shall be deemed to be one and the same Agreement
|
Section 11
|
Applicable Law.
This Agreement shall be governed and construed in accordance with the laws of the State of New York without regard to the conflict of laws principles thereof. The parties hereby irrevocably consent to the personal jurisdiction of the Federal and State courts located in New York, and waive any defense based upon improper venue, inconvenient venue or lack of personal jurisdiction.
|
|
WESTERN GAS RESOURCES, INC.
|
|
|
|
|
|
|
|
|
By:
|
/s/ Albert L. Richey
|
|
Name:
|
Albert L. Richey
|
|
Title:
|
Senior Vice President and Treasurer
|
|
WESTERN GAS HOLDINGS, LLC
|
|
|
|
|
|
|
|
|
By:
|
/s/ Donald R. Sinclair
|
|
Name:
|
Donald R. Sinclair
|
|
Title:
|
President and Chief Executive Officer
|
1.
|
The AMH Indemnification Agreement dated March 3, 2014 and entered into by and between APC Midstream Holdings LLC and Indemnitee.
|
2.
|
The KWC Indemnification Agreement dated March 14, 2016 and entered into by and between Kerr-McGee Worldwide Corporation and Indemnitee.
|
1.1
|
“
Lender Claim
” means any and all claims, damages, losses, liabilities, costs, or expenses whatsoever (including without limitation attorneys’ fees and expenses) which Indemnitee may incur (or which may be claimed against Indemnitee by any person or entity whatsoever), by reason of, or arising out of, any Proceeding against Borrower or Indemnitee in connection with (a) the obligations of the Borrower under the Restated Credit Agreement, but solely to the extent attributable to the Area A Loan or any indebtedness incurred by Borrower to refinance Indebtedness incurred pursuant to the Area A Loan and (b) obligations of Borrower for Debt Securities issued to refinance the obligations enumerated in clause (a) of this definition, in either case only to the extent not otherwise satisfied by the assets of the Borrower.
|
1.2
|
“
Lender Claimant
” means the Administrative Agent, the Issuing Bank, the Syndication Agent, the Documentation Agent, the Swingline Lender, the Trustee, any Lender, any Holder, any Related Party of the foregoing, or any other Person that may assert a Lender Claim.
|
1.3
|
“
Proceeding
” means any threatened, pending or completed action, suit, claim, arbitration, alternate dispute resolution mechanism, investigation, inquiry, administrative hearing or any other actual, threatened or completed proceeding, whether made by or brought in the right of a Lender Claimant or otherwise, in which Indemnitee or Borrower was, is or will be involved as a party or otherwise.
|
1.4
|
Capitalized terms used and not otherwise defined herein shall have the meanings ascribed to such terms in the Restated Credit Agreement or the Indenture.
|
2.1
|
Indemnification by Indemnitor
. Subject to the limitations set forth in
Section 2.2
below, Indemnitor shall indemnify and hold harmless Indemnitee from and against any Lender Claim. The indemnification obligation of Indemnitor pursuant to this Section 2.1 constitutes a continuation of the Assigned USH2 Rights and Obligations assumed by Indemnitor pursuant to the Merger Agreement and Indemnitor’s agreement therein to be bound by the same terms and conditions in the USH2
|
2.2
|
Conditions Precedent
. Notwithstanding anything contained in
Section 2.1
to the contrary, the Indemnitor shall not have any indemnification obligation under this Agreement unless Indemnitee has exhausted all of its remedies, if any, under the Partnership Agreement and under applicable law to collect from Borrower the amount of any Lender Claim;
provided
,
however
, that Indemnitee need not exhaust any remedies against Borrower to the extent Indemnitee reasonably determines that the expense anticipated to be incurred by Indemnitee in pursuing such claim against Borrower with respect to collection of the amount of the Lender Claim would exceed the anticipated recovery from Borrower with respect to such claim.
|
2.3
|
Lender Claims
.
|
(a)
|
Notice of Lender Claim
. If any Lender Claimant notifies Indemnitee with respect to any Lender Claim, then Indemnitee will promptly give written notice to Indemnitor; provided, however, that no delay on the part of Indemnitee in notifying Indemnitor will relieve Indemnitor from any obligation under this
Section 2.3(a)
.
|
(b)
|
Assumption of Defense, etc
. Indemnitor will be entitled to participate in the defense of any Lender Claim that is the subject of a notice given by Indemnitee pursuant to
Section 2.3(a)
. In addition, Indemnitor will have the right to assume the defense of such Lender Claim with counsel of its choice reasonably satisfactory to Indemnitee so long as (i) Indemnitor gives written notice to Indemnitee within fifteen (15) days after Indemnitee has given notice of the Lender Claim that Indemnitor will indemnify Indemnitee from and against the entirety of the Lender Claim; (ii) Indemnitor provides Indemnitee with evidence reasonably acceptable to Indemnitee that Indemnitor will have adequate financial resources to defend against the Lender Claim and fulfill its indemnification obligations hereunder; (iii) Indemnitee has not been advised by counsel that an actual or potential conflict exists between Indemnitee and Indemnitor in connection with the defense of the Lender Claim; and (iv) settlement of an adverse judgment with respect to, or Indemnitor’s conduct of the defense of, the Lender Claim is not, in the good faith judgment of Indemnitee, likely to be adverse to Indemnitee’s reputation or continuing business interests. Indemnitee may retain separate co-counsel at its sole cost and expense and participate in the defense of the Lender Claim.
|
(c)
|
Limitations on Indemnitor
. Indemnitor will not consent to the entry of any judgment or enter into any compromise or settlement with respect to the Lender Claim without the prior written consent of Indemnitee unless such judgment, compromise or settlement (i) provides for the payment by Indemnitor of money
|
(d)
|
Indemnitee’s Control
. If Indemnitor does not deliver to Indemnitee the notice contemplated by
Section 2.3(b)
within fifteen (15) days after Indemnitee has given notice of the Lender Claim pursuant to
Section 2.3(a)
, or otherwise at any time fails to conduct the defense of the Lender Claim actively and diligently, Indemnitee may defend the Lender Claim in a good faith and reasonable manner, and may consent to the entry of any judgment or enter into any compromise or settlement with respect to the Lender Claim in any manner it may deem appropriate (and Indemnitee need not consult with, or obtain any consent from, Indemnitor in connection therewith).
|
2.4
|
Procedure for Notification
. Subject to
Section 2.3
, to obtain indemnification under this Agreement, Indemnitee shall submit to Indemnitor a written request, including therein or therewith such documentation and information as is reasonably available to Indemnitee and is reasonably necessary to determine whether and to what extent Indemnitee is entitled to indemnification under this Agreement. The delay or omission to notify Indemnitor will not relieve Indemnitor from any liability which it may have to Indemnitee otherwise than under this Agreement.
|
2.5
|
Presumption
. It shall be presumed that Indemnitee is entitled to indemnification under this Agreement if Indemnitee has submitted a request for indemnification in accordance with
Section 2.3(a)
, and Indemnitor shall, to the fullest extent not prohibited by law, have the burden of proof to overcome that presumption in connection with the making by any person, persons or entity of any determination contrary to that presumption.
|
2.6
|
Payment and Set-Off
. Indemnitor shall make any indemnification payment required under this Agreement promptly following request therefor (or, in the event that Indemnitor elects to participate in or assume the defense of a Lender Claim in accordance with this
Section 2
, promptly after any settlement or entry of any final judgment with respect to such Lender Claim), subject to Indemnitor’s right to rebut the presumption set forth in
Section 2.5
. Indemnitee may set off against any amounts that it must pay to Indemnitor under any agreement or instrument any amounts that Indemnitor must pay to Indemnitee under this Agreement.
|
3.1
|
Maintenance of Minimum Net Worth
. Indemnitor covenants and agrees with Indemnitee that it shall maintain at all times a net worth (determined without regard to Indemnitor’s limited partner interest in Borrower) of no less than the maximum amount of any Lender Claim for which Indemnitee could seek indemnification pursuant to
Section 2.1
hereof should an event described in
Section 1.1
hereof occur; provided that the amount of such potential Lender Claim shall be determined without regard to any assets of the Borrower that could be used to satisfy such potential Lender Claim.
|
3.2
|
Books and Records; Audits
. Indemnitor shall keep, and will cause each of its Subsidiaries (if any) to keep, complete and accurate books and records of its transactions in accordance with good accounting practices on the basis of GAAP. Indemnitee may, upon thirty (30) days’ written notice to Indemnitor) (but in no event more than once each fiscal year), request that an audit of Indemnitor’s books and records be performed by be performed (at Indemnitee’s sole expense), in order to provide Indemnitee with such assurance as it deems reasonable and necessary with respect to Indemnitor’s financial condition.
|
Section 4
|
Waiver of Right to Subrogation.
In the event of any payment under this Agreement, Indemnitor expressly waives any right to subrogation with respect to any of the rights of recovery of Indemnitee or any Lender Claimant. Indemnitor also expressly waives any right to indemnification it may have under the Partnership Agreement with respect to any payment under this Agreement.
|
Section 5
|
Survival.
The provisions of this Agreement shall remain in full force and effect notwithstanding termination of the Restated Credit Agreement, any of the Loan Documents, or any agreement related thereto or related to the Transactions, so long as any Lender Claim remains outstanding.
|
Section 6
|
Severability.
If any term or provision of this Agreement shall be held to be illegal, invalid or unenforceable in any respect, then such term or provision shall be fully severable from this Agreement, this Agreement shall be construed and enforced as if such illegal, invalid or unenforceable term or provision had never been a part of this Agreement, and the remaining terms and provisions of this Agreement shall remain in full force and effect and shall not be affected by such illegal, invalid or unenforceable term or provision or by its severance from this Agreement.
|
Section 7
|
Entire Agreement.
This Agreement constitutes the entire agreement between the parties hereto pertaining to the subject matter hereof, and any and all other written or oral agreements relating to the subject matter hereof existing between the parties hereto are expressly cancelled. For the avoidance of doubt, nothing in this
Section 7
shall be deemed to invalidate any provision of the Partnership Agreement.
|
Section 8
|
Successors and Assigns.
Indemnitor agrees that all the rights, benefits and privileges herein and hereby conferred upon Indemnitee shall vest in, and be enforceable by, Indemnitee and its successors and assigns, and shall bind Indemnitor’s successors and assigns.
|
Section 9
|
Notices.
All notices, requests, demands and other communications under this Agreement shall be in writing and shall be deemed to have been duly given if (a) delivered by hand and receipted for by the party to whom said notice or other communication shall have been directed, (b) mailed by certified or registered mail with postage prepaid, on the third business day after the date on which it is so mailed, (c) mailed by reputable overnight courier and receipted for by the party to whom said notice or other communication shall have been directed or (d) sent by facsimile transmission, with receipt of oral confirmation that such transmission has been received:
|
a.
|
If to Indemnitee to:
|
b.
|
If to Indemnitor to:
|
Section 10
|
Counterparts.
This Agreement may be executed in counterparts, each of which shall be deemed to be an original, and all of which, taken together, shall be deemed to be one and the same Agreement
|
Section 11
|
Applicable Law.
This Agreement shall be governed and construed in accordance with the laws of the State of New York without regard to the conflict of laws principles thereof. The parties hereby irrevocably consent to the personal jurisdiction of the Federal and State courts located in New York, and waive any defense based upon improper venue, inconvenient venue or lack of personal jurisdiction.
|
|
KERR-McGEE WORLDWIDE CORPORATION
|
|
|
|
|
|
|
|
|
By:
|
/s/ Robert G. Gwin
|
|
Name:
|
Robert G. Gwin
|
|
Title:
|
President
|
|
WESTERN GAS HOLDINGS, LLC
|
|
|
|
|
|
|
|
|
By:
|
/s/ Donald R. Sinclair
|
|
Name:
|
Donald R. Sinclair
|
|
Title:
|
President and Chief Executive Officer
|
|
|
Year Ended December 31,
|
||||||||||||||||||
thousands
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) before income taxes
|
|
$
|
610,666
|
|
|
$
|
59,739
|
|
|
$
|
495,729
|
|
|
$
|
292,559
|
|
|
$
|
203,379
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges
|
|
122,100
|
|
|
123,680
|
|
|
87,892
|
|
|
64,806
|
|
|
48,871
|
|
|||||
Distributions from equity investments
|
|
103,423
|
|
|
98,298
|
|
|
81,022
|
|
|
22,136
|
|
|
20,660
|
|
|||||
Amortization of capitalized interest
|
|
3,491
|
|
|
2,375
|
|
|
2,095
|
|
|
934
|
|
|
485
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Equity income, net – affiliates
|
|
78,717
|
|
|
71,251
|
|
|
57,836
|
|
|
22,948
|
|
|
16,042
|
|
|||||
Capitalized interest
|
|
5,562
|
|
|
8,318
|
|
|
9,832
|
|
|
11,945
|
|
|
6,196
|
|
|||||
Net income before taxes attributable to noncontrolling interests
|
|
10,963
|
|
|
10,101
|
|
|
14,025
|
|
|
10,816
|
|
|
14,890
|
|
|||||
Earnings
|
|
$
|
744,438
|
|
|
$
|
194,422
|
|
|
$
|
585,045
|
|
|
$
|
334,726
|
|
|
$
|
236,267
|
|
Fixed charges:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, including capitalized interest
|
|
$
|
120,483
|
|
|
$
|
122,190
|
|
|
$
|
86,598
|
|
|
$
|
63,742
|
|
|
$
|
48,256
|
|
Interest component of rent expense
|
|
1,617
|
|
|
1,490
|
|
|
1,294
|
|
|
1,064
|
|
|
615
|
|
|||||
Fixed charges
|
|
$
|
122,100
|
|
|
$
|
123,680
|
|
|
$
|
87,892
|
|
|
$
|
64,806
|
|
|
$
|
48,871
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Preferred unit distribution
(1)
|
|
$
|
45,784
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Combined fixed charges and preferred unit distribution
|
|
$
|
167,884
|
|
|
$
|
123,680
|
|
|
$
|
87,892
|
|
|
$
|
64,806
|
|
|
$
|
48,871
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
(2)
|
|
6.1x
|
|
|
1.6x
|
|
|
6.7x
|
|
|
5.2x
|
|
|
4.8x
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to combined fixed charges and preferred unit distribution
(2) (3)
|
|
4.4x
|
|
|
1.6x
|
|
|
6.7x
|
|
|
5.2x
|
|
|
4.8x
|
|
(1)
|
Represents the distributions associated with the Series A Preferred units issued in March 2016 and April 2016.
|
(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, 2013 and 2012.
|
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.
|
I am 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 my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me 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 my 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 my conclusion 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.
|
I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
/s/ Benjamin M. Fink
|
|
Benjamin M. Fink
President, Chief Executive Officer,
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, 2016
, 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 23, 2017
|
|
|
|
|
|
|
|
/s/ Benjamin M. Fink
|
|
|
Benjamin M. Fink
|
|
|
President, Chief Executive Officer,
|
|
|
Chief Financial Officer and Treasurer
|
|
|
Western Gas Holdings, LLC
|
|
|
(as general partner of Western Gas Partners, LP)
|