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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
o
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Non-accelerated filer
o
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Smaller reporting company
o
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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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7A.
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8.
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9.
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9A.
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9B.
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Item
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Page
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10.
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11.
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12.
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13.
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14.
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15.
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Owned and
Operated
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Operated
Interests
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Non-Operated
Interests
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Equity Interests
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Natural gas gathering systems
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14
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1
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5
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2
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Natural gas treating facilities
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8
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—
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—
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1
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Natural gas processing facilities
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13
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3
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—
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2
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NGL pipelines
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3
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—
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—
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3
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Natural gas pipelines
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4
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—
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—
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—
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Oil pipeline
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1
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—
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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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Gas Compression (HP)
(1)
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Processing or Treating Capacity (MMcf/d)
(1) (2)
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Average Gathering, Processing and Transportation Throughput (MMcf/d)
(3)
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Average Gathering, Processing and Transportation Throughput (MBbls/d)
(4)
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Rocky Mountains
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Gathering, Processing and Treating
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7,732
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5,044
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482,108
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3,161
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2,258
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—
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Transportation
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1,037
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41
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28,002
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—
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99
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35
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Mid-Continent
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Gathering
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2,067
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1,498
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90,214
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—
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66
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—
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North-central Pennsylvania
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Gathering
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632
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368
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70,750
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—
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805
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—
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Texas
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Gathering, Processing and Treating
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1,060
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1,017
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61,000
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1,000
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430
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—
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Transportation
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1,145
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12
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34,395
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—
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—
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81
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Total
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13,673
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7,980
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766,469
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4,161
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3,658
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116
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(1)
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All system metrics are presented on a gross basis.
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(2)
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Capacity excludes 170 MBbls/d of fractionation capacity attributable to the Mont Belvieu JV.
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(3)
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Includes 100% of Chipeta throughput, 50% of Newcastle throughput, 22% of Rendezvous throughput and 14.81% of Fort Union throughput.
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(4)
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Represents total throughput measured in barrels, consisting of throughput from our Chipeta NGL pipeline, our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput and our 33.33% share of average FRP throughput. See
Properties
below for further descriptions of these systems.
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thousands except unit and percent amounts
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Acquisition
Date
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Percentage
Acquired
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Borrowings
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Cash
On Hand
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Common
Units Issued to Anadarko
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Class C
Units Issued to Anadarko
(3)
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TEFR Interests
(1)
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03/03/2014
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Various
(1)
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$
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350,000
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$
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6,250
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308,490
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—
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DBM
(2)
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11/25/2014
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100
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%
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475,000
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298,327
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—
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10,913,853
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(1)
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We 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. TEG consists of two NGL gathering systems that link natural gas processing plants to TEP. TEP is an NGL pipeline that originates in Skellytown, Texas and extends approximately 593 miles to Mont Belvieu, Texas. FRP is a 435-mile NGL pipeline that extends from Weld County, Colorado to Skellytown, Texas. The interests in these entities are accounted for under the equity method of accounting. In connection with the issuance of the common units, our general partner purchased
6,296
general partner units in exchange for the general partner’s proportionate capital contribution of
$0.4 million
.
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(2)
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We acquired Nuevo Midstream, LLC (“Nuevo”) from a third party. Following the acquisition, we changed the name of Nuevo to Delaware Basin Midstream, LLC (“DBM”). The assets acquired include cryogenic processing plants, a gas gathering system, and related facilities and equipment, which are collectively referred to as the “DBM complex” and serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico.
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(3)
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See
Note 4—Equity and Partners’ Capital
i
n the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K for a discussion of the Class C units.
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thousands except unit and per-unit amounts
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Common
Units Issued
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GP Units Issued
(1)
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Price Per
Unit
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Underwriting
Discount and
Other Offering
Expenses
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Net
Proceeds
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Continuous Offering Program - 2014
(2)
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1,133,384
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23,132
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$
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73.48
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$
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1,738
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$
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83,245
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November 2014 equity offering
(3)
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8,620,153
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153,061
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70.85
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18,583
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602,999
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(1)
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Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution.
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(2)
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Represents common and general partner units issued during the
year ended December 31, 2014
, pursuant to our registration statement filed with the SEC in August 2012 authorizing the issuance of up to $125.0 million of common units (the “Continuous Offering Program”). 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 Continuous Offering Program 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.
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(3)
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Includes the issuance of
1,120,153
common units pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise were
$77.0 million
. Beginning with this partial exercise, our general partner elected not to make a corresponding capital contribution to maintain a 2.0% interest in us. See
Note 4—Equity and Partners’ Capital
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
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•
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Pursuing accretive acquisitions.
We expect to continue to pursue accretive acquisitions of midstream energy assets from Anadarko and third parties.
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Capitalizing on organic growth opportunities.
We expect to grow certain of our systems organically over time by meeting Anadarko’s and our other customers’ midstream service needs that result from their drilling activity in our areas of operation. We continually evaluate economically attractive organic expansion opportunities in existing or new areas of operation that allow us to leverage our existing infrastructure, operating expertise and customer relationships by constructing and expanding systems to meet new or increased demand of our services.
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Attracting third-party volumes to our systems.
We expect to 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 substantial majority of the commodity price uncertainty through the use of fee-based contracts and fixed-price hedges.
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Maintaining investment grade ratings.
We intend to operate at appropriate leverage and distribution coverage levels in line with other partnerships in our sector that have received investment grade credit ratings. By maintaining an investment grade credit rating with all three credit rating agencies, in part through staying within leverage ratios appropriate for investment-grade partnerships, we believe that we will be able to pursue strategic acquisitions and large growth projects at a lower cost of fixed-income capital, which would enhance their accretion and overall return.
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Affiliation with Anadarko.
We believe Anadarko is motivated to promote and support the successful execution of our business plan and to use its relationships throughout the energy industry, including those with producers and customers in the United States, to pursue projects that help to enhance the value of our business. See
Our Relationship with Anadarko Petroleum Corporation
below.
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Relatively stable and predictable cash flows.
Our cash flows are largely protected from fluctuations caused by commodity price volatility due to (i) the approximately 80% of our services that are provided pursuant to long-term, fee-based agreements and (ii) the commodity price swap agreements that limit our exposure to commodity price changes with respect to a substantial majority of our percent-of-proceeds and keep-whole contracts. For the year ended
December 31, 2014
,
99%
of our gross margin was derived from either long-term, fee-based contracts or from percent-of-proceeds or keep-whole agreements that were hedged with commodity price swap agreements. On December 31, 2014, our commodity price swap agreements for the Hilight and Newcastle systems and the Granger complex expired without renewal. On June 30, 2015, and September 30, 2015, our commodity price swap agreements for the DJ Basin complex and Hugoton system, respectively, will expire. See
Risk Factors
under Item 1A and
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
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Financial flexibility to pursue expansion and acquisition opportunities
.
We believe our operating cash flows, borrowing capacity, and access to debt and equity capital markets provide us with the financial flexibility to competitively pursue acquisition and expansion opportunities and to execute our strategy across capital market cycles. We currently have investment grade ratings from all three of the major rating agencies and, as of
December 31, 2014
, we had
$510.0 million
of outstanding borrowings and
$12.8 million
in outstanding letters of credit issued under our
$1.2 billion
senior unsecured revolving credit facility (“RCF”).
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Substantial presence in basins with historically strong producer economics.
Certain of our gathering and processing systems and facilities, such as the DBM complex, the DJ Basin complex and the Brasada complex serve production in liquids-rich growth areas where the hydrocarbon production contains not only natural gas, but also oil, condensate, and significant amounts of NGLs. Production in liquids-rich areas offers our customers higher margins and superior economics compared to basins in which the gas is predominantly dry. In addition, our interests in the Anadarko-Operated and Non-Operated Marcellus gathering systems serve dry gas production from the Marcellus shale, which historically has provided attractive producer returns due to the overall scale and quality of the underlying resource, as well as its access to premium markets in the northeast United States. See
Properties
below for further asset descriptions.
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Well-positioned, well-maintained and efficient assets.
We believe that our asset portfolio, which is located in geographically diverse areas of operation, provides us with opportunities to expand and attract additional volumes to our systems from multiple productive reservoirs. Moreover, our portfolio includes an integrated package of high-quality, well-maintained assets for which we have implemented modern processing, treating, measuring and operating technologies.
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Consistent track record of accretive acquisitions.
Since our IPO in 2008, our management team has successfully executed nine related-party acquisitions and six third-party acquisitions, with an aggregate value of $4.8 billion. Our management team has demonstrated its ability to identify, evaluate, negotiate, consummate and integrate strategic acquisitions and expansion projects, and it intends to use its experience and reputation to continue to grow the Partnership through accretive acquisitions, focusing on opportunities to improve throughput volumes and cash flows.
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Gathering.
At the initial stages of the midstream value chain, a network of typically smaller diameter pipelines known as gathering systems directly connect to wellheads 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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•
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Stabilization.
In connection with our gathering services, we sometimes retain, stabilize and sell drip condensate, which falls out of the natural gas stream during gathering. Stabilization is a process that separates the heavier hydrocarbons (which also serve as valuable commodities) found in natural gas, typically referred to as “liquids-rich” natural gas, from the lighter components by using a distillation process or by reducing the pressure and letting the more volatile components flash. We provide stabilization for condensate at many of our processing plants (such as the DJ Basin and Brasada complexes).
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Compression.
Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which allows the natural gas to be gathered more efficiently and delivered into a higher pressure system, processing plant or pipeline. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Since wells produce at progressively lower field pressures as they deplete, field compression is needed to maintain throughput across the gathering system.
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Treating and dehydration.
To the extent that gathered natural gas contains water vapor or contaminants, such as carbon dioxide and hydrogen sulfide, it is dehydrated to remove the saturated water and treated to separate the carbon dioxide and hydrogen sulfide from the gas stream.
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Processing.
Processing separates the heavier and more valuable hydrocarbon components, which are extracted as NGLs, from the remaining residue. The remaining residue is then designated for long-haul pipeline transportation or commercial use.
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Fractionation.
Fractionation is the process of applying various levels of higher pressure and lower temperature to separate a stream of NGLs into ethane, propane, normal butane, isobutane and natural gasoline for end-use sale.
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Storage, transportation and marketing.
Once the raw natural gas has been treated or processed and the raw NGL mix has been fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located both throughout the pipeline network and at major market centers to better accommodate seasonal demand and daily supply-demand shifts. We do not currently offer storage services.
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Fee-based.
Under fee-based arrangements, the service provider typically receives a fee for each unit of natural gas gathered, treated and/or processed at its facilities. As a result, the price per unit received by the service provider does not vary with commodity price changes, minimizing the service provider’s direct commodity price risk exposure.
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Percent-of-proceeds, percent-of-value or percent-of-liquids.
Percent-of-proceeds, percent-of-value or percent-of-liquids arrangements may be used for gathering and processing services. Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue and/or NGLs or a percentage of the actual residue and/or NGLs at the tailgate. These types of arrangements expose the processor to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price of natural gas and/or NGLs.
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Keep-whole.
Keep-whole arrangements may be used for processing services. Under these arrangements, the service provider keeps 100% of the NGLs produced, and the processed natural gas, or value of the gas, is returned to the producer. Since some of the gas is used and removed during processing, the processor compensates the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas utilized. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.
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Firm.
Firm transportation service requires the reservation of pipeline capacity by a customer between certain receipt and delivery points. 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 a usage fee based on the amount of natural gas transported.
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Interruptible.
Interruptible transportation 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 of gas actually 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 on the 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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Compressor Stations
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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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1
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450
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—
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14,320
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—
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—
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Northeast Wyoming
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Fort Union
(1)
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Gathering & Treating
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1
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294
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—
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5,454
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1
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318
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Northeast Wyoming
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Hilight
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Gathering & Processing
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1
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60
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13
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37,357
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1
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1,563
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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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1
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2,660
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1
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180
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Southwest Wyoming
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Granger complex
(2)
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Gathering & Processing
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2
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500
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8
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43,950
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1
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896
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Southwest Wyoming
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Red Desert complex
(3)
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Gathering & Processing
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2
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173
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9
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62,262
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1
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1,110
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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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1
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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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8
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1,480
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32
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173,488
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6
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4,405
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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 Patrick Draw cryogenic processing plant and the Red Desert cryogenic processing plant.
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(4)
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We have a 22% interest in the Rendezvous gathering system, which is operated by a third party.
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•
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Customers.
Anadarko provided 67% of the throughput at the Bison treating facility for the year ended
December 31, 2014
. The remaining throughput was from one third-party producer.
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•
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Supply and delivery points
. The Bison treating facility treats and compresses gas from coal-bed methane wells in the Powder River Basin of Wyoming. The Bison pipeline, operated by TransCanada Corporation, is connected directly to the facility, which is currently the only inlet into the pipeline. The Bison treating facility also has access to Fort Union’s
pipeline and Meritage Midstream Services II, LLC’s Thunder Creek pipeline.
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•
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Customers.
Anadarko and the other members of Fort Union (Copano Pipelines/Rocky Mountains, LLC
, Crestone Powder River LLC, and Bargath, LLC) are the only firm shippers on the Fort Union system. To the extent capacity on the system is not used by the members, it is available to third parties under interruptible agreements.
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•
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Supply.
Substantially all of Fort Union’s gas supply is comprised of coal-bed methane volumes that are either produced or gathered by the customers noted above throughout the Powder River Basin. As of
December 31, 2014
, the Fort Union system gathered gas from 1,900 Anadarko-operated coal-bed methane wells producing in the Big George coal play and a nearby multi-seam coal fairway. Anadarko had a working interest in over 1.1 million gross acres within the Powder River Basin as of
December 31, 2014
. Another of the Fort Union owners has a comparable working interest in a large majority of Anadarko’s producing coal-bed methane wells. The two remaining Fort Union owners gather gas for delivery to Fort Union under contracts with acreage dedications from multiple producers in the heart of the basin and from the coal-bed methane producing area near Sheridan, Wyoming.
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•
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Delivery points.
The Fort Union system delivers coal-bed methane gas to the hub in Glenrock, Wyoming, which has access to the following interstate pipelines:
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◦
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Colorado Interstate Gas Company LLC’s pipeline (“CIG”);
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◦
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Tallgrass Interstate Gas Transmission system’s pipeline (“TIGT”); and
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◦
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Wyoming Interstate Company’s pipeline (“WIC”).
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•
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Customers.
Gas gathered and processed through the Hilight system is primarily from numerous third-party customers, with the six largest producers providing 71% of the system throughput during the year ended
December 31, 2014
.
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•
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Supply.
The Hilight gathering system serves the gas gathering needs of several conventional producing fields in Johnson, Campbell, Natrona and Converse Counties. Our customers, including Anadarko, have historically maintained and more recently increased throughput by developing new prospects and performing workovers.
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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 its truck and rail loading facilities.
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•
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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 80% of the system throughput during the year ended
December 31, 2014
. The largest producer provided 57% of the throughput during the year ended
December 31, 2014
.
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•
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Supply.
The Newcastle gathering system and plant primarily service gas production from the Clareton and Finn-Shurley fields in Weston County, Wyoming. Due to infill drilling and enhanced production techniques, producers have continued to maintain production levels.
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•
|
Delivery points.
Propane products from the Newcastle plant are typically sold locally by truck, and the butane/gasoline mix products are transported to the Hilight plant for further fractionation. Residue from the Newcastle system is delivered into Black Hills Corporation’s MGTC, Inc. (“MGTC”) intrastate pipeline, a Hinshaw pipeline that supplies local markets in Wyoming, for transport, distribution and sale.
|
•
|
Customers.
For the year ended December 31, 2014, 7% of the Granger complex throughput was from Anadarko and the remaining throughput was from various third-party customers, with the five largest shippers providing 86% of the system throughput.
|
•
|
Supply.
The Granger complex is supplied by the Moxa Arch and the Jonah and Pinedale anticline fields. The Granger gas gathering system had 667 active receipt points as of December 31, 2014.
|
•
|
Delivery points.
The residue from the Granger complex can be delivered to the following major pipelines:
|
◦
|
CIG;
|
◦
|
Berkshire Hathaway Energy’s Kern River pipeline (“Kern River pipeline”) and our Mountain Gas Transportation, Inc.’s (“MGTI”) pipeline via a connect with Tesoro Logistics LP’s (“Tesoro”) Rendezvous pipeline (“Rendezvous pipeline”);
|
◦
|
The Williams Companies, Inc.’s Northwest pipeline (“NWPL”); and
|
◦
|
our Overland Trail Transmission, LLC’s pipeline (“OTTCO”).
|
•
|
Customers.
For the year ended
December 31, 2014
, 4% of the Red Desert complex throughput was from Anadarko and the remaining throughput was from various third-party customers, with the six largest producers providing 70% of the system throughput.
|
•
|
Supply.
The Red Desert complex gathers, compresses, treats and processes natural gas and fractionates NGLs produced in the eastern portion of the Greater Green River Basin, providing service primarily to the Red Desert and Washakie Basins.
|
•
|
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.
|
•
|
Customers.
Tesoro and Anadarko are the only firm shippers on the Rendezvous gathering system. To the extent capacity on the system is not used by those shippers, it is available to third parties under interruptible agreements.
|
•
|
Supply and delivery points.
The Rendezvous gathering system provides mainline 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 Questar Pipeline Company’s pipeline (“Questar pipeline”), NWPL and the Kern River pipeline via the Rendezvous pipeline.
|
Location
|
|
Asset
|
|
Type
|
|
Processing / Treating Plants
|
|
Processing / Treating Capacity (MMcf/d)
|
|
Compressor Stations
|
|
Compression Horsepower
|
|
Gathering Systems
|
|
Pipeline Miles
|
||||||
Colorado
|
|
DJ Basin complex
(1)
|
|
Gathering, Processing & Treating
|
|
6
|
|
|
619
|
|
|
21
|
|
|
196,928
|
|
|
2
|
|
|
3,213
|
|
Utah
|
|
Chipeta
(2)
|
|
Processing
|
|
2
|
|
|
970
|
|
|
—
|
|
|
91,307
|
|
|
—
|
|
|
—
|
|
Utah
|
|
Clawson
|
|
Gathering & Treating
|
|
1
|
|
|
40
|
|
|
1
|
|
|
6,310
|
|
|
1
|
|
|
47
|
|
Utah
|
|
Helper
|
|
Gathering & Treating
|
|
2
|
|
|
52
|
|
|
2
|
|
|
14,075
|
|
|
1
|
|
|
67
|
|
Total
|
|
|
|
|
|
11
|
|
|
1,681
|
|
|
24
|
|
|
308,620
|
|
|
4
|
|
|
3,327
|
|
(1)
|
The DJ Basin complex includes the Platte Valley cryogenic processing plant, the Wattenberg gathering system, the Fort Lupton processing plant, the Fort Lupton JT processing plant, the Hambert JT processing plant, the Platteville amine treating plant and the Lancaster plant. Train II of the Lancaster plant is currently under construction and is expected to be completed during the second quarter of 2015.
|
(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.
|
•
|
Customers.
For the year ended
December 31, 2014
, 68% of the DJ Basin complex throughput was from Anadarko and the remaining throughput was from various third-party customers, with the largest providing 21% of the throughput.
|
•
|
Supply and delivery points.
There were 2,881 active receipt points connected to the DJ Basin complex as of
December 31, 2014
. The DJ Basin complex is primarily supplied by the Wattenberg field, in which Anadarko controls 840,000 gross acres and drilled 369 wells and completed 330 wells during the year ended
December 31, 2014
.
|
◦
|
Anadarko’s Wattenberg plant;
|
◦
|
DCP Midstream’s (“DCP”) Spindle, Mewbourn and Platteville plants; and
|
◦
|
AKA Energy Group, LLC’s Gilcrest plant.
|
•
|
Customers.
Anadarko is the largest customer on the Chipeta system with 82% of the system throughput for the year ended
December 31, 2014
. The balance of throughput on the system during the year ended
December 31, 2014
was from nine third-party customers.
|
•
|
Supply.
The Chipeta system is well positioned to access Anadarko and third-party production in the Uinta Basin where Anadarko controls 245,000 gross acres. Chipeta’s inlet is connected to Anadarko’s Natural Buttes gathering system, the Questar pipeline and the Three Rivers Gathering, LLC’s system, which is owned by Ute Energy and another third party.
|
•
|
Delivery points.
The Chipeta plant delivers NGLs to MAPL, which provides transportation through Enterprise’s Seminole pipeline (“Seminole pipeline”) and TEP’s pipeline in West Texas and ultimately to the NGL fractionation and storage facilities in Mont Belvieu, Texas. The Chipeta plant has natural gas delivery points through the following pipelines:
|
◦
|
CIG;
|
◦
|
Questar pipeline; and
|
◦
|
WIC.
|
•
|
Customers.
Anadarko is the largest shipper on the Clawson gathering system with 99% of the total throughput on the system during the year ended
December 31, 2014
. The remaining throughput on the system was from one third-party producer.
|
•
|
Supply.
The Clawson Springs field covers 7,000 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 each of the Helper and Cardinal Draw fields.
|
•
|
Delivery points.
The Helper gathering system delivers into the Questar pipeline.
|
Location
|
|
Asset
|
|
Type
|
|
Compressor Stations
|
|
Compression Horsepower
|
|
Gathering Systems
|
|
Pipeline Miles
|
||||
Southwest Kansas & Oklahoma
|
|
Hugoton
|
|
Gathering
|
|
42
|
|
|
90,214
|
|
|
1
|
|
|
2,067
|
|
North-central Pennsylvania
|
|
Non-Operated Marcellus
(1)
|
|
Gathering
|
|
4
|
|
|
70,750
|
|
|
2
|
|
|
481
|
|
North-central Pennsylvania
|
|
Anadarko-Operated Marcellus
(2)
|
|
Gathering
|
|
—
|
|
|
—
|
|
|
3
|
|
|
151
|
|
Total
|
|
|
|
|
|
46
|
|
|
160,964
|
|
|
6
|
|
|
2,699
|
|
(1)
|
We own a 33.75% interest (the “Non-Operated Marcellus Interest”) in the Liberty and Rome gas gathering systems (the “Non-Operated Marcellus Interest gathering systems”), with a third party as the operator.
|
(2)
|
We own a 33.75% interest (the “Anadarko-Operated Marcellus Interest”) in the Larry’s Creek, Seely and Warrensville gas gathering systems (the “Anadarko-Operated Marcellus Interest gathering systems”), with Anadarko as the operator.
|
•
|
Customers.
Anadarko is the largest customer on the Hugoton gathering system with 86% of the system throughput during the year ended
December 31, 2014
. Two third-party shippers account for 8% of the system throughput, with the balance from various other third-party shippers.
|
•
|
Supply.
The Hugoton field continues to be a long-life, low-decline asset for Anadarko, which has an extensive acreage position in the field with 470,000 gross acres. The Hugoton system is well positioned to gather volumes that may be produced from successful new wells drilled by third-party producers.
|
•
|
Delivery points.
The Hugoton gathering system is connected to the Satanta plant, which is owned by Anadarko (49%) and a third party. The Satanta plant processes NGLs and helium, and delivers residue into the Kansas Gas Service’s pipeline and Southern Star Central Gas Pipeline, Inc.’s pipeline. The system is also connected to DCP’s National Helium Plant, which extracts NGLs and delivers residue into Energy Transfer Partners, LP’s (“ETP”) Panhandle Eastern Pipe Line.
|
•
|
Customers.
As of
December 31, 2014
, there were seven and five priority shippers on the Non-Operated Marcellus Interest gathering systems and the Anadarko-Operated Marcellus Interest gathering systems, respectively, including Anadarko. For the year ended December 31, 2014, Anadarko represented 21% and 36% 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, 2014
, Anadarko had a working interest in over 722,000 gross acres within the Marcellus shale. The Non-Operated Marcellus Interest gathering systems have access to Transcontinental Gas Pipeline Company, LLC’s pipeline (“TRANSCO”), Tennessee Gas Pipeline Company, LLC’s pipeline and Millennium Pipeline Company, LLC’s pipeline. The Anadarko-Operated Marcellus Interest gathering systems have access to TRANSCO.
|
Location
|
|
Asset
|
|
Type
|
|
Processing / Treating Plants
|
|
Processing / Treating Capacity (MMcf/d)
|
|
Processing Capacity (MBbls/d)
|
|
Compressor Stations
|
|
Compression Horsepower
|
|
Gathering Systems
|
|
Pipeline Miles
|
|||||||
East Texas
|
|
Dew
|
|
Gathering
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
36,085
|
|
|
1
|
|
|
324
|
|
East Texas
|
|
Pinnacle
(1)
|
|
Gathering & Treating
|
|
1
|
|
|
500
|
|
|
—
|
|
|
1
|
|
|
1,340
|
|
|
1
|
|
|
270
|
|
East Texas
|
|
Mont Belvieu JV
(2)
|
|
Processing
|
|
2
|
|
|
—
|
|
|
170
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
South Texas
|
|
Brasada complex
(3)
|
|
Gathering, Processing & Treating
|
|
2
|
|
|
200
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
71
|
|
West Texas
|
|
Haley
|
|
Gathering
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
142
|
|
West Texas
|
|
DBM complex
(4)
|
|
Gathering, Processing & Treating
|
|
3
|
|
|
300
|
|
|
—
|
|
|
4
|
|
|
23,575
|
|
|
1
|
|
|
253
|
|
Total
|
|
|
|
|
|
8
|
|
|
1,000
|
|
|
170
|
|
|
14
|
|
|
61,000
|
|
|
5
|
|
|
1,060
|
|
(1)
|
The Pinnacle system includes the Bethel treating facility.
|
(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)
|
The table above excludes 15MBbls/d of condensate stabilization capacity at the Brasada complex.
|
(4)
|
The table above excludes 1,800 gpm of amine treating capacity at the DBM complex.
|
•
|
Customers.
Anadarko is the largest shipper on the Dew gathering system with 99% of the total throughput on the system during the year ended
December 31, 2014
. The remaining throughput on the system was from two third-party producers.
|
•
|
Supply.
As of
December 31, 2014
, Anadarko had 794 producing wells in the Bossier play and controlled 111,000 gross acres in the area.
|
•
|
Delivery points.
The Dew gathering system has delivery points on Kinder Morgan, Inc.’s Tejas pipeline (“Tejas pipeline”) and with Pinnacle, which is the primary delivery point and is described in more detail below.
|
•
|
Customers.
Anadarko is the largest shipper on the Pinnacle gathering system with 92% of system throughput for the year ended
December 31, 2014
. The remaining throughput on the system during that period was from five third-party shippers.
|
•
|
Supply.
The Pinnacle gathering system is well positioned to provide sour gas gathering and treating services to the five-county area over which it extends, including the Cotton Valley Lime and Reef formations, which contain relatively high concentrations of hydrogen sulfide and carbon dioxide.
|
•
|
Delivery points.
The Pinnacle gathering system is connected to the following pipelines:
|
◦
|
Atmos Energy’s Texas pipeline;
|
◦
|
Midcoast Energy Partners, LP’s East Texas system;
|
◦
|
Energy Transfer Fuels’ pipeline;
|
◦
|
Enterprise Texas Pipeline, LP’s pipeline;
|
◦
|
ETC Texas Pipeline, Ltd’s pipeline; and
|
◦
|
the Tejas pipeline.
|
•
|
Customers.
The Mont Belvieu JV does not directly contract with customers, but rather is allocated volumes from Enterprise based on the available capacity of the other trains at Enterprise’s NGL fractionation complex in Mont Belvieu, Texas.
|
•
|
Supply and delivery points.
Enterprise receives volumes at its fractionation complex in Mont Belvieu, Texas via a large number of pipelines that terminate there, including the Seminole pipeline, Skelly-Belvieu Pipeline Company, LLC’s pipeline and TEP. Individual NGLs are delivered to end users either through customer-owned pipelines that are connected to nearby petrochemical plants or via export terminal.
|
•
|
Customers.
Anadarko provides 100% of the throughput to the Brasada complex. Anadarko delivers gas and condensate to the plant on behalf of itself and its upstream partners.
|
•
|
Supply.
Supply of gas and NGLs for the facility comes from Anadarko’s production in the Eagleford shale, in which Anadarko controls 416,000 gross acres.
|
•
|
Delivery points.
The facility delivers residue gas into the Eagle Ford Midstream system operated by NET Midstream, LLC. It delivers the NGLs into the South Texas NGL Pipeline System operated by Enterprise.
|
•
|
Customers.
Anadarko’s production represented 68% of the Haley gathering system’s throughput for the year ended
December 31, 2014
. The remaining throughput was attributable to one third-party producer.
|
•
|
Supply.
As of
December 31, 2014
, Anadarko had access to 445,000 gross acres in the greater Delaware Basin, a portion of which is gathered by the Haley gathering system.
|
•
|
Delivery points.
The Haley gathering system has multiple delivery points. The primary delivery points are to Kinder Morgan, Inc.’s El Paso Natural Gas pipeline (“El Paso pipeline”) or Enterprise GC, LLC’s pipeline for ultimate delivery into ETP’s Oasis pipeline (“Oasis pipeline”). We also have the ability to deliver into Southern Union Energy Services’ pipeline for further delivery into the Oasis pipeline. The pipelines at these delivery points provide transportation to both the Waha and Houston Ship Channel markets.
|
•
|
Customers.
Gas gathered and processed through the DBM complex is primarily from nine third party producers, with the three largest producers providing 77% of the system throughput for the year ended
December 31, 2014
.
|
•
|
Supply.
Supply of gas and NGLs for the complex comes from production from the Delaware Sands, Avalon Shale, Bone Springs and Wolfcamp formations in the Delaware Basin portion of the Permian Basin. Anadarko currently holds 445,000 gross acres within the Delaware Basin.
|
•
|
Delivery points.
Residue gas produced at the facility is delivered to an interconnect with the El Paso pipeline. NGL production is delivered to an interconnect with DCP’s Sand Hills pipeline. As of
December 31, 2014
, there was an additional NGL interconnect under construction at our DBM complex with an expected in-service date during the first quarter of 2015.
|
Location
|
|
Asset
|
|
Type
|
|
Compressor Stations
|
|
Operational Horsepower
|
|
Pipeline Miles
|
|||
Northeast Wyoming
|
|
MIGC
(1)
|
|
Gas
|
|
10
|
|
|
24,828
|
|
|
262
|
|
Southwest Wyoming
|
|
OTTCO
|
|
Gas
|
|
1
|
|
|
3,174
|
|
|
217
|
|
Utah
|
|
GNB NGL
(1)
|
|
NGL
|
|
—
|
|
|
—
|
|
|
32
|
|
Colorado, Kansas, Oklahoma
|
|
White Cliffs
(1) (2)
|
|
Oil
|
|
—
|
|
|
—
|
|
|
526
|
|
Colorado, Oklahoma, Texas
|
|
FRP
(1) (3)
|
|
NGL
|
|
1
|
|
|
7,500
|
|
|
435
|
|
Texas, Oklahoma
|
|
TEG
|
|
NGL
|
|
6
|
|
|
1,895
|
|
|
117
|
|
Texas
|
|
TEP
(1) (3)
|
|
NGL
|
|
1
|
|
|
25,000
|
|
|
593
|
|
Total
|
|
|
|
|
|
19
|
|
|
62,397
|
|
|
2,182
|
|
(1)
|
MIGC, GNB NGL, White Cliffs, FRP and TEP are regulated by the Federal Energy Regulatory Commission (“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 87% of throughput for the year ended
December 31, 2014
. The remaining throughput on the MIGC system was from 17 third-party shippers. MIGC offers both forward-haul and backhaul transportation services and is certificated for 175 MMcf/d of firm transportation capacity.
|
•
|
Supply.
As of
December 31, 2014
, Anadarko had a working interest in over 1.1 million gross acres within the Powder River Basin. Anadarko’s gross acreage includes substantial undeveloped acreage positions in the Big George coal play and the multiple seam coal fairway to the north of the Big George coal play. MIGC receives gas from various coal-bed methane gathering systems throughout 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, 2014
, 12% of OTTCO’s throughput was from Anadarko. The remaining throughput on the OTTCO transportation system was from two third-party shippers. Revenues on the OTTCO transportation system are generated from contract demand charges and volumetric fees paid by shippers under firm and interruptible gas transportation agreements. Most of OTTCO’s gas transportation agreements are month-to-month with the remainder generally having terms of less than one year. OTTCO has one current third-party firm transportation agreement for 21 MMBtu/d, which extends through December 2021.
|
•
|
Supply and delivery points.
Supply points to the OTTCO transportation system include 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 interconnection with Kern River pipeline.
|
•
|
Customers.
Anadarko was the only shipper on the GNB NGL pipeline for the year ended
December 31, 2014
.
|
•
|
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, 2014
. 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 over 200 MBbls/d. These expansion projects are scheduled to be completed in mid-to-late 2015.
|
•
|
Supply.
The White Cliffs pipeline is supplied by production from the DJ Basin and offers the only direct route from the DJ Basin to Cushing, Oklahoma.
|
•
|
Delivery points.
The White Cliffs pipeline delivery point is SemCrude’s storage facility in Cushing, Oklahoma, a major crude oil marketing center, which ultimately delivers to Gulf Coast and mid-continent refineries. At the point of origin, it has a 300,000-barrel storage facility adjacent to a truck-unloading facility.
|
•
|
Front Range Pipeline.
FRP provides takeaway capacity from the DJ Basin in Northeast Colorado. FRP has injection points from gas plants in Weld County, Colorado (including our Lancaster plant), which is part of 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, 2014
, FRP had two committed shippers, including Anadarko and provides capacity for other shippers at the posted FERC tariff rate.
|
•
|
Texas Express Gathering.
TEG consists of two NGL gathering systems that provide plants in North Texas, the Texas panhandle and West Oklahoma with access to NGL takeaway capacity on TEP. TEG had one committed shipper during the year ended
December 31, 2014
.
|
•
|
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, 2014
and provides capacity for other shippers at the posted FERC tariff rates.
|
•
|
Lancaster Train II in the DJ Basin:
We are currently constructing the second train of the Lancaster plant, which is part of the DJ Basin complex. The second train is designed to have a capacity of 300 MMcf/d and is expected to begin service during the second quarter of 2015. Anadarko has agreed to a fee-based contract with a 10-year throughput guarantee of 200 MMcf/d, which will begin on the plant’s in-service date.
|
•
|
DBM Trains IV and V in West Texas:
We are currently preparing for the construction of an additional cryogenic unit at our DBM complex with 200 MMcf/d of designed processing capacity and an in-service date expected during the first quarter of 2016. We have also made progress payments towards the construction of another cryogenic unit at our DBM complex (Train V), with an expected in-service date of mid-2016.
|
System
|
|
Competitor(s)
|
|
|
|
Anadarko-Operated Marcellus Interest gathering systems
|
|
Regency Energy Partners LP (formerly PVR Midstream) and National Fuel Gas Midstream Corporation
|
Bison treating facility
|
|
Thunder Creek Gas Services, LLC and Fort Union (treating only)
|
Brasada gathering system, stabilization facility and processing complex
|
|
Enterprise, ETP and Kinder Morgan, Inc.
|
Chipeta processing complex
|
|
Tesoro and Kinder Morgan, Inc.
|
Dew and Pinnacle gathering systems and Pinnacle treating facility
|
|
ETC Texas Pipeline, Ltd., Midcoast Energy Partners, LP (East Texas), XTO Energy and the Tejas pipeline
|
DJ Basin gathering system, treating facility and processing complex
|
|
DCP and AKA Energy Group, LLC
|
Fort Union gathering system and treating facility
|
|
Bison treating facility (carbon dioxide treating services only), MIGC, Thunder Creek Gas Services, LLC and TransCanada Corporation
|
Granger gathering system and processing complex
|
|
Williams Field Services, Enterprise/Jonah Gas Gathering Company and Tesoro
|
Haley gathering system
|
|
Anadarko’s Delaware Basin Joint Venture, Enterprise GC, LP, Regency Gas Services, LP and Targa Midstream Services, LP
|
Helper and Clawson gathering systems and treating facilities
|
|
XTO Energy
|
Hilight gathering system and processing plant
|
|
DCP, ONEOK Gas Gathering Company, Thunder Creek Gas Services, LLC, Crestwood-Access, Tallgrass Energy Partners, LP and Rowdy Gathering Company
|
Hugoton gathering system
|
|
ONEOK Gas Gathering Company, DCP and Linn Energy
|
Mont Belvieu JV fractionation trains
|
|
Targa Resources LP, Phillips 66, Lone Star NGL LLC and ONEOK Partners, LP
|
Newcastle gathering system and processing plant
|
|
DCP
|
Non-Operated Marcellus Interest gathering systems
|
|
Regency Energy Partners, LP (formerly PVR Midstream)
|
DBM gathering system, treating facility and processing complex
|
|
Anadarko’s Delaware Basin Joint Venture, Regency Gas Services, Enterprise GC, LP and Targa Midstream, LP
|
Red Desert gathering system and processing complex
|
|
Williams Field Services and Tesoro
|
Rendezvous gathering system
|
|
No significant direct competition
|
•
|
rates, services, and terms and conditions of service;
|
•
|
types of services that may be offered to customers;
|
•
|
certification and construction of new facilities;
|
•
|
acquisition, extension, disposition or abandonment of facilities;
|
•
|
maintenance of accounts and records;
|
•
|
internet posting requirements for available capacity, discounts and other matters;
|
•
|
pipeline segmentation to allow multiple simultaneous shipments under the same contract;
|
•
|
capacity release to create a secondary market for transportation services;
|
•
|
relationships between affiliated companies involved in certain aspects of the natural gas business;
|
•
|
initiation and discontinuation of services;
|
•
|
market manipulation in connection with interstate sales, purchases or transportation of natural gas and NGLs; and
|
•
|
participation by interstate pipelines in cash management arrangements.
|
•
|
our ability to pay distributions to our unitholders;
|
•
|
our and Anadarko’s assumptions about the energy market;
|
•
|
future throughput, including Anadarko’s production, which is gathered or processed by or transported through our assets;
|
•
|
our operating results;
|
•
|
competitive conditions;
|
•
|
technology;
|
•
|
the availability of capital resources to fund acquisitions, capital expenditures and other contractual obligations, and our ability to access those resources from Anadarko or through the debt or equity capital markets;
|
•
|
the supply of, demand for, and the price of, oil, natural gas, NGLs and related products or services;
|
•
|
weather and natural disasters;
|
•
|
inflation;
|
•
|
the availability of goods and services;
|
•
|
general economic conditions, either internationally or domestically or in the jurisdictions in which we are doing business;
|
•
|
federal, state and local laws, including those that limit Anadarko and other producers’ hydraulic fracturing or other oil and natural gas operations;
|
•
|
environmental liabilities;
|
•
|
legislative or regulatory changes, including changes affecting our status as a partnership for federal income tax purposes;
|
•
|
changes in the financial or operational condition of Anadarko;
|
•
|
changes in Anadarko’s capital program, strategy or desired areas of focus;
|
•
|
our commitments to capital projects;
|
•
|
our ability to use our RCF;
|
•
|
the creditworthiness of Anadarko or our other counterparties, including financial institutions, operating partners and other parties;
|
•
|
our ability to repay debt;
|
•
|
our ability to mitigate a substantial majority of the commodity price risks inherent in our percent-of-proceeds and keep-whole contracts;
|
•
|
conflicts of interest among us, our general partner, WGP and its general partner, and affiliates, including Anadarko;
|
•
|
our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;
|
•
|
our ability to acquire assets on acceptable terms;
|
•
|
non-payment or non-performance of Anadarko or other significant customers, including under our gathering, processing and transportation agreements and our $260.0 million note receivable from Anadarko;
|
•
|
the timing, amount and terms of future issuances of equity and debt securities; and
|
•
|
other factors discussed below and elsewhere in this Item 1A, under the caption
Critical Accounting Policies and Estimates
included under Item 7 of this Form 10-K, and in our other public filings and press releases.
|
•
|
the volatility of natural gas and oil prices, which could have a negative effect on the value of Anadarko’s oil and natural gas properties, its drilling programs or its ability to finance its operations;
|
•
|
the availability of capital on an economic basis to fund Anadarko’s exploration and development activities;
|
•
|
a reduction in or reallocation of Anadarko’s capital budget, which could reduce the gathering, transportation and treating volumes available to us as a midstream operator, limit our midstream opportunities for organic growth or limit the inventory of midstream assets we may acquire from Anadarko;
|
•
|
Anadarko’s ability to replace reserves;
|
•
|
Anadarko’s operations in foreign countries, which are subject to political, economic and other uncertainties;
|
•
|
Anadarko’s drilling and operating risks, including potential environmental liabilities;
|
•
|
transportation capacity constraints and interruptions;
|
•
|
adverse effects of governmental and environmental regulation; and
|
•
|
adverse effects from current or future litigation.
|
•
|
domestic and worldwide economic and geopolitical conditions;
|
•
|
weather conditions and seasonal trends;
|
•
|
the ability to develop recently discovered fields or deploy new technologies to existing fields;
|
•
|
the levels of domestic production and consumer demand, as affected by, among other things, concerns over inflation, geopolitical issues and the availability and cost of credit;
|
•
|
the availability of imported or a market for exported liquefied natural gas (“LNG”);
|
•
|
the availability of transportation systems with adequate capacity;
|
•
|
the volatility and uncertainty of regional pricing differentials, such as in the Mid-Continent or Rocky Mountains;
|
•
|
the price and availability of alternative fuels;
|
•
|
the effect of energy conservation measures;
|
•
|
the nature and extent of governmental regulation and taxation; and
|
•
|
the forecasted supply and demand for, and prices of, natural gas, NGLs and other commodities.
|
•
|
the prices of, level of production of, and demand for natural gas;
|
•
|
the volume of natural gas we gather, compress, process, treat and transport;
|
•
|
the volumes and prices of NGLs and condensate that we retain and sell;
|
•
|
demand charges and volumetric fees associated with our transportation services;
|
•
|
the level of competition from other midstream energy companies;
|
•
|
regulatory action affecting the supply of or demand for natural gas, the rates we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and
|
•
|
prevailing economic conditions.
|
•
|
our level of capital expenditures;
|
•
|
our level of operating and maintenance and general and administrative costs;
|
•
|
our debt service requirements and other liabilities;
|
•
|
fluctuations in our working capital needs;
|
•
|
our ability to borrow funds and access capital markets;
|
•
|
our treatment as a flow-through entity for U.S. federal income tax purposes;
|
•
|
restrictions contained in debt agreements to which we are a party; and
|
•
|
the amount of cash reserves established by our general partner.
|
•
|
incur additional indebtedness or guarantee other indebtedness;
|
•
|
grant liens to secure obligations other than our obligations under the Notes or RCF or agree to restrictions on our ability to grant additional liens to secure our obligations under the Notes or RCF;
|
•
|
engage in transactions with affiliates;
|
•
|
make any material change to the nature of our business from the midstream energy business; or
|
•
|
enter into a merger, consolidate, liquidate, wind up or dissolve.
|
•
|
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
|
•
|
our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flows required to make interest payments on our debt;
|
•
|
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
|
•
|
our flexibility in responding to changing business and economic conditions may be limited.
|
•
|
mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies;
|
•
|
an inability to successfully integrate the acquired assets or businesses;
|
•
|
the assumption of unknown liabilities;
|
•
|
limitations on rights to indemnity from the seller;
|
•
|
mistaken assumptions about the overall costs of equity or debt;
|
•
|
the diversion of management’s and employees’ attention from other business concerns;
|
•
|
unforeseen difficulties operating in new geographic areas; and
|
•
|
customer or key employee losses at the acquired businesses.
|
•
|
damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;
|
•
|
inadvertent damage from construction, farm and utility equipment;
|
•
|
leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;
|
•
|
leaks of natural gas containing hazardous quantities of hydrogen sulfide from our Pinnacle gathering system or Bethel treating facility;
|
•
|
fires and explosions; and
|
•
|
other hazards that could also result in personal injury, loss of life, pollution, natural resource damages and/or suspension of operations.
|
•
|
Neither our partnership agreement nor any other agreement requires Anadarko to pursue a business strategy that favors us.
|
•
|
Anadarko is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to parties other than us.
|
•
|
Our general partner is allowed to take into account the interests of parties other than us, such as Anadarko, in resolving conflicts of interest.
|
•
|
The officers of our general partner will also devote significant time to the business of Anadarko and will be compensated by Anadarko accordingly.
|
•
|
Our partnership agreement limits the liability of and reduces the default state law fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under state law.
|
•
|
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
|
•
|
Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.
|
•
|
Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner.
|
•
|
Our general partner determines which costs incurred by it are reimbursable by us.
|
•
|
Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make IDR payments.
|
•
|
Our partnership agreement permits us to classify up to $31.8 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of the general partner interest or the IDRs.
|
•
|
Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
|
•
|
Our general partner intends to limit its liability regarding our contractual and other obligations.
|
•
|
Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.
|
•
|
Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.
|
•
|
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
|
•
|
Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to the IDRs without the approval of the Special Committee of the Board of Directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
|
•
|
how to allocate corporate opportunities among us and its affiliates;
|
•
|
whether to exercise its limited call right;
|
•
|
how to exercise its voting rights with respect to the units it owns;
|
•
|
whether to exercise its registration rights;
|
•
|
whether to elect to reset target distribution levels; and
|
•
|
whether to consent to any merger or consolidation of the Partnership or amendment to the partnership agreement.
|
•
|
provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
|
•
|
provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in the best interest of the Partnership;
|
•
|
provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
|
•
|
provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is any of the following:
|
(a)
|
approved by the Special Committee of the Board of Directors of our general partner, although our general partner is not obligated to seek such approval;
|
(b)
|
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
|
(c)
|
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
|
(d)
|
fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
|
•
|
our existing unitholders’ proportionate ownership interest in us will decrease;
|
•
|
the amount of cash available for distribution on each unit may decrease;
|
•
|
the ratio of taxable income to distributions may increase;
|
•
|
the relative voting strength of each previously outstanding unit may be diminished; and
|
•
|
the market price of the common units may decline.
|
•
|
we were conducting business in a state but had not complied with that particular state’s partnership statute; or
|
•
|
such unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
|
•
|
changes in investor or analyst estimates of Anadarko’s and our financial performance or our future distribution growth;
|
•
|
the public’s reaction to Anadarko’s or our press releases, announcements and filings with the SEC;
|
•
|
legislative or regulatory changes affecting our status as a partnership for federal income tax purposes;
|
•
|
fluctuations in broader securities market prices and volumes, particularly among securities of midstream companies and securities of publicly traded limited partnerships;
|
•
|
changes in market valuations of similar companies;
|
•
|
departures of key personnel;
|
•
|
commencement of or involvement in litigation;
|
•
|
variations in our quarterly results of operations or those of midstream companies;
|
•
|
variations in the amount of our quarterly cash distributions;
|
•
|
future issuances and sales of our common units; and
|
•
|
changes in general conditions in the U.S. economy, financial markets or the midstream industry.
|
|
Fourth
Quarter
|
|
Third
Quarter
|
|
Second
Quarter
|
|
First
Quarter
|
||||||||
2014
|
|
|
|
|
|
|
|
||||||||
High Price
|
$
|
75.29
|
|
|
$
|
79.81
|
|
|
$
|
76.57
|
|
|
$
|
66.50
|
|
Low Price
|
60.09
|
|
|
71.15
|
|
|
65.51
|
|
|
58.50
|
|
||||
Distribution per common unit
|
0.700
|
|
|
0.675
|
|
|
0.650
|
|
|
0.625
|
|
||||
2013
|
|
|
|
|
|
|
|
||||||||
High Price
|
$
|
64.07
|
|
|
$
|
65.16
|
|
|
$
|
65.11
|
|
|
$
|
59.81
|
|
Low Price
|
57.54
|
|
|
54.58
|
|
|
55.57
|
|
|
46.82
|
|
||||
Distribution per common unit
|
0.600
|
|
|
0.580
|
|
|
0.560
|
|
|
0.540
|
|
|
|
Total Quarterly Distribution
Target Amount
|
|
Marginal Percentage
Interest in Distributions
|
||
|
|
|
Unitholders
|
|
General Partner
|
|
Minimum quarterly distribution
|
|
$0.300
|
|
98.1%
|
|
1.9%
|
First target distribution
|
|
up to $0.345
|
|
98.1%
|
|
1.9%
|
Second target distribution
|
|
above $0.345 up to $0.375
|
|
85.1%
|
|
14.9%
|
Third target distribution
|
|
above $0.375 up to $0.450
|
|
75.1%
|
|
24.9%
|
Thereafter
|
|
above $0.450
|
|
50.1%
|
|
49.9%
|
(1)
|
Net income earned on and subsequent to the date of our acquisitions of Partnership assets is allocated to the general partner and the limited partners, including any subordinated and Class C unitholders, in accordance with their respective weighted-average ownership percentages, and when applicable, giving effect to incentive distributions allocable to the general partner. Prior to our acquisition of the Partnership assets, all income is attributed to Anadarko. All subordinated units were converted into common units on August 15, 2011, on a one-for-one basis. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. See
Note 4—Equity and Partners’ Capital
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(2)
|
Includes affiliate, third-party and equity investment throughput, excluding the noncontrolling interest owners’ proportionate share of throughput.
|
(3)
|
Represents total throughput measured in barrels consisting of throughput from our Chipeta NGL pipeline, our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput and our 33.33% share of average FRP throughput.
|
(4)
|
Calculated as total revenues for natural gas assets less cost of product for natural gas assets plus distributions from our equity investments in Fort Union and Rendezvous, which are measured in Mcf, and excluding the noncontrolling interest owners’ proportionate share of revenue and cost of product.
|
(5)
|
Calculated as total revenues for crude/NGL assets less cost of product for crude/NGL assets plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, and the TEFR Interests, which are measured in barrels.
|
(6)
|
Average for period. Calculated as Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (as defined under the caption
How We Evaluate Our Operations
under Item 7 of this Form 10-K) divided by total throughput (MMcf/d) attributable to Western Gas Partners, LP for natural gas assets.
|
(7)
|
Average for period. Calculated as Adjusted gross margin for crude/NGL assets (as defined under the caption
How We Evaluate Our Operations
under Item 7 of this Form 10-K), divided by total throughput (MBbls/d) for crude/NGL assets.
|
(8)
|
Adjusted EBITDA attributable to Western Gas Partners, LP (“Adjusted EBITDA”) and Distributable cash flow are not defined in the generally accepted accounting principles in the United States (“GAAP”). For definitions and reconciliations of Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, please see the caption
How We Evaluate Our Operations
under Item 7 of this Form 10-K.
|
|
|
Owned and
Operated
|
|
Operated
Interests
|
|
Non-Operated
Interests
|
|
Equity Interests
|
||||
Natural gas gathering systems
|
|
14
|
|
|
1
|
|
|
5
|
|
|
2
|
|
Natural gas treating facilities
|
|
8
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Natural gas processing facilities
|
|
13
|
|
|
3
|
|
|
—
|
|
|
2
|
|
NGL pipelines
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Natural gas pipelines
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Oil pipeline
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
•
|
We completed the acquisition of DBM from a third party. DBM’s assets serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. See
Acquisitions
under Items 1 and 2 of this Form 10-K for additional information.
|
•
|
We issued 10,913,853 Class C units to a subsidiary of Anadarko, at a price of $68.72 per unit, generating proceeds of $750.0 million, all of which was used to fund a portion of the acquisition of DBM.
|
•
|
We issued
8,620,153
common units to the public, generating net proceeds of
$603.0 million
, including the general partner’s proportionate capital contribution, part of which was used to fund a portion of the acquisition of DBM.
|
•
|
We issued
1,133,384
common units to the public under our Continuous Offering Program (as defined and discussed in
Registered Securities
within this Item 7), generating net proceeds of
$83.2 million
, including the general partner’s proportionate capital contribution. Net proceeds were used for general partnership purposes, including funding capital expenditures. See
Equity Offerings
under Items 1 and 2 of this Form 10-K for additional information.
|
•
|
In April 2014, we completed construction and commenced operations of the 300 MMcf/d Train I at the Lancaster plant (located in the DJ Basin complex) in Northeast Colorado. We are currently constructing the 300 MMcf/d Train II at the same plant, with operations expected to commence in the second quarter of 2015.
|
•
|
We issued $400.0 million aggregate principal amount of 5.450% Senior Notes due 2044 and an additional $100.0 million aggregate principal amount of 2.600% Senior Notes due 2018. Net proceeds were used to repay amounts then outstanding under our RCF. See
Liquidity and Capital Resources
within this Item 7 for additional information.
|
•
|
We completed the acquisition of Anadarko’s 20% interests in TEG and TEP, and its 33.33% interest in FRP. See
Acquisitions
under Items 1 and 2 of this Form 10-K for additional information.
|
•
|
We entered into an amended and restated $1.2 billion (expandable to $1.5 billion) senior unsecured RCF replacing our $800.0 million credit facility. See
Liquidity and Capital Resources
within this Item 7 for additional information.
|
•
|
We raised our distribution to
$0.70
per unit for the
fourth
quarter of
2014
, representing a
4%
increase
over the distribution for the
third
quarter of
2014
and a
17%
increase
over the distribution for the
fourth
quarter of
2013
.
|
•
|
Throughput attributable to Western Gas Partners, LP for natural gas assets totaled
3,493
MMcf/d for the
year ended December 31, 2014
, representing a
9%
increase
compared to the
year ended December 31, 2013
.
|
•
|
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
$0.65
per Mcf for the
year ended December 31, 2014
, representing a
16%
increase
compared to the
year ended December 31, 2013
.
|
•
|
Adjusted gross margin for crude/NGL assets (as defined under the caption
How We Evaluate Our Operations
within this Item 7) averaged
$1.75
per Bbl for the
year ended December 31, 2014
, representing a
67%
increase
compared to the
year ended December 31, 2013
.
|
•
|
expenses associated with annual and quarterly reporting;
|
•
|
tax return and Schedule K-1 preparation and distribution expenses;
|
•
|
expenses associated with listing on the New York Stock Exchange; 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
|
|
2014
|
|
2013
|
|
2012
|
||||||
Reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP to Operating income
|
|
|
|
|
|
|
||||||
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets
|
|
$
|
822,932
|
|
|
$
|
654,924
|
|
|
$
|
544,853
|
|
Adjusted gross margin for crude/NGL assets
|
|
73,714
|
|
|
15,274
|
|
|
13,221
|
|
|||
Adjusted gross margin attributable to Western Gas Partners, LP
|
|
896,646
|
|
|
670,198
|
|
|
558,074
|
|
|||
Adjusted gross margin attributable to noncontrolling interests
|
|
20,183
|
|
|
17,416
|
|
|
20,983
|
|
|||
Equity income, net
|
|
57,836
|
|
|
22,948
|
|
|
16,042
|
|
|||
Less:
|
|
|
|
|
|
|
||||||
Distributions from equity investees
|
|
81,022
|
|
|
22,136
|
|
|
20,660
|
|
|||
Operation and maintenance
|
|
199,305
|
|
|
168,657
|
|
|
140,106
|
|
|||
General and administrative
|
|
34,242
|
|
|
29,751
|
|
|
99,212
|
|
|||
Property and other taxes
|
|
25,353
|
|
|
23,244
|
|
|
19,688
|
|
|||
Depreciation, amortization and impairments
|
|
183,156
|
|
|
145,916
|
|
|
120,608
|
|
|||
Operating income
|
|
$
|
451,587
|
|
|
$
|
320,858
|
|
|
$
|
194,825
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2014
|
|
2013
|
|
2012
|
||||||
Reconciliation of Adjusted EBITDA attributable to Western Gas Partners, LP to Net income attributable to Western Gas Partners, LP
|
|
|
|
|
|
|
||||||
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
$
|
645,969
|
|
|
$
|
457,773
|
|
|
$
|
377,929
|
|
Less:
|
|
|
|
|
|
|
||||||
Distributions from equity investees
|
|
81,022
|
|
|
22,136
|
|
|
20,660
|
|
|||
Non-cash equity-based compensation expense
(1)
|
|
4,095
|
|
|
3,575
|
|
|
73,508
|
|
|||
Interest expense
|
|
76,766
|
|
|
51,797
|
|
|
42,060
|
|
|||
Income tax expense
|
|
2,255
|
|
|
4,219
|
|
|
20,690
|
|
|||
Depreciation, amortization and impairments
(2)
|
|
180,587
|
|
|
143,375
|
|
|
118,279
|
|
|||
Other expense
(2)
|
|
—
|
|
|
175
|
|
|
1,665
|
|
|||
Add:
|
|
|
|
|
|
|
||||||
Equity income, net
|
|
57,836
|
|
|
22,948
|
|
|
16,042
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Other income
(2) (3)
|
|
325
|
|
|
419
|
|
|
368
|
|
|||
Income tax benefit
|
|
228
|
|
|
1,864
|
|
|
—
|
|
|||
Net income attributable to Western Gas Partners, LP
|
|
$
|
376,533
|
|
|
$
|
274,627
|
|
|
$
|
134,377
|
|
Reconciliation of Adjusted EBITDA attributable to Western Gas Partners, LP to Net cash provided by operating activities
|
|
|
|
|
|
|
||||||
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
$
|
645,969
|
|
|
$
|
457,773
|
|
|
$
|
377,929
|
|
Adjusted EBITDA attributable to noncontrolling interests
|
|
16,583
|
|
|
13,348
|
|
|
17,214
|
|
|||
Interest income (expense), net
|
|
(59,866
|
)
|
|
(34,897
|
)
|
|
(25,160
|
)
|
|||
Non-cash equity-based compensation expense
(1)
|
|
(175
|
)
|
|
(54
|
)
|
|
(69,791
|
)
|
|||
Debt-related amortization and other items, net
|
|
2,736
|
|
|
2,449
|
|
|
2,319
|
|
|||
Current income tax benefit (expense)
|
|
556
|
|
|
29,536
|
|
|
9,419
|
|
|||
Other income (expense), net
(3)
|
|
336
|
|
|
253
|
|
|
(1,292
|
)
|
|||
Distributions from equity investments in excess of cumulative earnings
|
|
(18,055
|
)
|
|
(4,438
|
)
|
|
—
|
|
|||
Changes in operating working capital:
|
|
|
|
|
|
|
||||||
Accounts receivable, net
|
|
(4,217
|
)
|
|
(34,019
|
)
|
|
22,916
|
|
|||
Accounts and natural gas imbalance payables and accrued liabilities, net
|
|
(52,530
|
)
|
|
21,952
|
|
|
5,045
|
|
|||
Other
|
|
3,470
|
|
|
(3,702
|
)
|
|
(552
|
)
|
|||
Net cash provided by operating activities
|
|
$
|
534,807
|
|
|
$
|
448,201
|
|
|
$
|
338,047
|
|
Cash flow information of Western Gas Partners, LP
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
|
$
|
534,807
|
|
|
$
|
448,201
|
|
|
$
|
338,047
|
|
Net cash used in investing activities
|
|
(2,621,559
|
)
|
|
(1,652,995
|
)
|
|
(1,357,537
|
)
|
|||
Net cash provided by financing activities
|
|
2,053,078
|
|
|
885,541
|
|
|
1,212,912
|
|
(1)
|
For the year ended December 31, 2012, includes $69.8 million of equity-based compensation associated with the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (the “Incentive Plan”) (as defined and described in
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K), paid and contributed by Anadarko.
|
(2)
|
Includes our 51% share prior to August 1, 2012, and our 75% share after August 1, 2012, of depreciation, amortization and impairments; other expense; and other income attributable to Chipeta Processing LLC (“Chipeta”). See
Note 2—Acquisitions
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(3)
|
Excludes income of
$0.5 million
for the
year ended December 31, 2014
, and
$1.6 million
for each of the years ended December 31, 2013 and 2012, related to a component of a gas processing agreement accounted for as a capital lease.
|
|
|
Year Ended December 31,
|
||||||||||
thousands except Coverage ratio
|
|
2014
|
|
2013
|
|
2012
|
||||||
Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP and calculation of the Coverage ratio
|
|
|
|
|
|
|
||||||
Distributable cash flow
|
|
$
|
531,136
|
|
|
$
|
380,529
|
|
|
$
|
309,945
|
|
Less:
|
|
|
|
|
|
|
||||||
Distributions from equity investees
|
|
81,022
|
|
|
22,136
|
|
|
20,660
|
|
|||
Non-cash equity-based compensation expense
(1)
|
|
4,095
|
|
|
3,575
|
|
|
73,508
|
|
|||
Interest expense, net (non-cash settled)
|
|
—
|
|
|
—
|
|
|
326
|
|
|||
Income tax (benefit) expense
|
|
2,027
|
|
|
2,355
|
|
|
20,690
|
|
|||
Depreciation, amortization and impairments
(2)
|
|
180,587
|
|
|
143,375
|
|
|
118,279
|
|
|||
Other expense
(2)
|
|
—
|
|
|
175
|
|
|
1,665
|
|
|||
Add:
|
|
|
|
|
|
|
||||||
Equity income, net
|
|
57,836
|
|
|
22,948
|
|
|
16,042
|
|
|||
Cash paid for maintenance capital expenditures
(2) (3)
|
|
45,225
|
|
|
29,850
|
|
|
36,459
|
|
|||
Capitalized interest
(4)
|
|
9,832
|
|
|
11,945
|
|
|
6,196
|
|
|||
Cash paid for (reimbursement of) income taxes
|
|
(90
|
)
|
|
552
|
|
|
495
|
|
|||
Other income
(2) (5)
|
|
325
|
|
|
419
|
|
|
368
|
|
|||
Net income attributable to Western Gas Partners, LP
|
|
$
|
376,533
|
|
|
$
|
274,627
|
|
|
$
|
134,377
|
|
Distributions declared
(6)
|
|
|
|
|
|
|
||||||
Limited partners
|
|
$
|
320,862
|
|
|
|
|
|
||||
General partner
|
|
121,194
|
|
|
|
|
|
|||||
Total
|
|
$
|
442,056
|
|
|
|
|
|
||||
Coverage ratio
|
|
1.20
|
|
x
|
|
|
|
(1)
|
For the year ended December 31, 2012, includes $69.8 million of equity-based compensation associated with the Incentive Plan (as defined and described in
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K), paid and contributed by Anadarko.
|
(2)
|
Includes our 51% share prior to August 1, 2012, and our 75% share after August 1, 2012, of depreciation, amortization and impairments; other expense; cash paid for maintenance capital expenditures; and other income attributable to Chipeta. See
Note 2—Acquisitions
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(3)
|
Net of a prior period adjustment reclassifying $0.7 million from capital expenditures to operating expenses for the year ended December 31, 2012.
|
(4)
|
For the year ended December 31, 2013, includes capitalized interest of $1.4 million for the construction of the Mont Belvieu JV fractionation trains, reflected as a component of the equity investment balance. For the year ended December 31, 2012, excludes $0.6 million of pre-acquisition capitalized interest attributable to the Non-Operated Marcellus Interest systems.
|
(5)
|
Excludes income of
$0.5 million
for the
year ended December 31, 2014
, and
$1.6 million
for each of the years ended December 31, 2013 and 2012, related to a component of a gas processing agreement accounted for as a capital lease.
|
(6)
|
Reflects cash distributions of
$2.65
per unit declared for the
year ended December 31, 2014
. See
Note 3—Partnership Distributions
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2014
|
|
2013
|
|
2012
|
||||||
General and administrative expenses
|
|
$
|
20,249
|
|
|
$
|
16,882
|
|
|
$
|
14,904
|
|
Public company expenses
|
|
8,006
|
|
|
7,152
|
|
|
6,830
|
|
|||
Total reimbursement
|
|
$
|
28,255
|
|
|
$
|
24,034
|
|
|
$
|
21,734
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2014
|
|
2013
|
|
2012
|
||||||
Gathering, processing and transportation of natural gas and natural gas liquids
|
|
$
|
647,451
|
|
|
$
|
482,542
|
|
|
$
|
382,330
|
|
Natural gas, natural gas liquids and condensate sales
|
|
612,854
|
|
|
541,244
|
|
|
508,339
|
|
|||
Other
|
|
13,458
|
|
|
5,977
|
|
|
3,807
|
|
|||
Total revenues
(1)
|
|
1,273,763
|
|
|
1,029,763
|
|
|
894,476
|
|
|||
Equity income, net
|
|
57,836
|
|
|
22,948
|
|
|
16,042
|
|
|||
Total operating expenses
(1)
|
|
880,012
|
|
|
731,853
|
|
|
715,693
|
|
|||
Operating income
|
|
451,587
|
|
|
320,858
|
|
|
194,825
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
|
|
(76,766
|
)
|
|
(51,797
|
)
|
|
(42,060
|
)
|
|||
Other income (expense), net
|
|
864
|
|
|
1,837
|
|
|
292
|
|
|||
Income before income taxes
|
|
392,585
|
|
|
287,798
|
|
|
169,957
|
|
|||
Income tax (benefit) expense
|
|
2,027
|
|
|
2,355
|
|
|
20,690
|
|
|||
Net income
|
|
390,558
|
|
|
285,443
|
|
|
149,267
|
|
|||
Net income attributable to noncontrolling interests
|
|
14,025
|
|
|
10,816
|
|
|
14,890
|
|
|||
Net income attributable to Western Gas Partners, LP
|
|
$
|
376,533
|
|
|
$
|
274,627
|
|
|
$
|
134,377
|
|
Key performance metrics
(2)
|
|
|
|
|
|
|
||||||
Adjusted gross margin attributable to Western Gas Partners, LP
|
|
$
|
896,646
|
|
|
$
|
670,198
|
|
|
$
|
558,074
|
|
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
645,969
|
|
|
457,773
|
|
|
377,929
|
|
|||
Distributable cash flow
|
|
531,136
|
|
|
380,529
|
|
|
309,945
|
|
(1)
|
Revenues include amounts earned from services provided to our affiliates, as well as from the sale of residue, condensate and NGLs to our affiliates. Operating expenses include amounts charged by our affiliates for services as well as reimbursement of amounts paid by affiliates to third parties on our behalf. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(2)
|
Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow are defined under the caption
How We Evaluate Our Operations—Non-GAAP financial measures
within this Item 7
.
For reconciliations of Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see
How We Evaluate Our Operations—Reconciliation to GAAP Measures
within this Item 7.
|
|
|
Year Ended December 31,
|
|||||||||||||
MMcf/d (except throughput measured in barrels)
|
|
2014
|
|
2013
|
|
Inc/
(Dec)
|
|
2012
|
|
Inc/
(Dec)
|
|||||
Throughput for natural gas assets
|
|
|
|
|
|
|
|
|
|
|
|||||
Gathering, treating and transportation
(1)
|
|
1,562
|
|
|
1,404
|
|
|
11
|
%
|
|
1,264
|
|
|
11
|
%
|
Processing
(1)
|
|
1,925
|
|
|
1,758
|
|
|
9
|
%
|
|
1,524
|
|
|
15
|
%
|
Equity investment
(2)
|
|
171
|
|
|
206
|
|
|
(17
|
)%
|
|
235
|
|
|
(12
|
)%
|
Total throughput for natural gas assets
|
|
3,658
|
|
|
3,368
|
|
|
9
|
%
|
|
3,023
|
|
|
11
|
%
|
Throughput attributable to noncontrolling interests for natural gas assets
|
|
165
|
|
|
168
|
|
|
(2
|
)%
|
|
228
|
|
|
(26
|
)%
|
Total throughput attributable to Western Gas Partners, LP for natural gas assets
(3)
|
|
3,493
|
|
|
3,200
|
|
|
9
|
%
|
|
2,795
|
|
|
14
|
%
|
Total throughput (MBbls/d) for crude/NGL assets
(4)
|
|
116
|
|
|
40
|
|
|
190
|
%
|
|
31
|
|
|
29
|
%
|
(1)
|
The combination of our Wattenberg and Platte Valley systems in 2014 into the entity now referred to as the “DJ Basin complex” (which also includes the Lancaster plant) resulted in the following: (i) the Wattenberg system throughput previously reported as “Gathering, treating and transportation” is now reported as “Processing” for all periods presented, and (ii) beginning in 2014, throughput both gathered and processed by the two systems is no longer separately reported.
|
(2)
|
Represents our 14.81% share of average Fort Union and our 22% share of average Rendezvous throughput. Excludes equity investment throughput measured in barrels (captured in “Total throughput (MBbls/d) for crude/NGL assets” as noted below).
|
(3)
|
Includes affiliate, third-party and equity investment throughput (as equity investment throughput is defined in the above footnote), excluding the noncontrolling interest owners’ proportionate share of throughput.
|
(4)
|
Represents total throughput measured in barrels, consisting of throughput from our Chipeta NGL pipeline, our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput, and our 33.33% share of average FRP throughput.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2014
|
|
2013
|
|
Inc/
(Dec)
|
|
2012
|
|
Inc/
(Dec)
|
||||||||
Gathering, processing and transportation of natural gas and natural gas liquids
|
|
$
|
647,451
|
|
|
$
|
482,542
|
|
|
34
|
%
|
|
$
|
382,330
|
|
|
26
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages and per-unit amounts
|
|
2014
|
|
2013
|
|
Inc/
(Dec)
|
|
2012
|
|
Inc/
(Dec)
|
||||||||
Natural gas sales
|
|
$
|
159,144
|
|
|
$
|
118,134
|
|
|
35
|
%
|
|
$
|
101,116
|
|
|
17
|
%
|
Natural gas liquids sales
|
|
417,459
|
|
|
391,608
|
|
|
7
|
%
|
|
377,377
|
|
|
4
|
%
|
|||
Drip condensate sales
|
|
36,251
|
|
|
31,502
|
|
|
15
|
%
|
|
29,846
|
|
|
6
|
%
|
|||
Total
|
|
$
|
612,854
|
|
|
$
|
541,244
|
|
|
13
|
%
|
|
$
|
508,339
|
|
|
6
|
%
|
Average price per unit:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas (per Mcf)
|
|
$
|
4.18
|
|
|
$
|
4.58
|
|
|
(9
|
)%
|
|
$
|
4.24
|
|
|
8
|
%
|
Natural gas liquids (per Bbl)
|
|
47.34
|
|
|
47.69
|
|
|
(1
|
)%
|
|
48.22
|
|
|
(1
|
)%
|
|||
Drip condensate (per Bbl)
|
|
80.83
|
|
|
76.62
|
|
|
5
|
%
|
|
75.88
|
|
|
1
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2014
|
|
2013
|
|
Inc/
(Dec)
|
|
2012
|
|
Inc/
(Dec)
|
||||||||
Other revenues
|
|
$
|
13,458
|
|
|
$
|
5,977
|
|
|
125
|
%
|
|
$
|
3,807
|
|
|
57
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2014
|
|
2013
|
|
Inc/
(Dec)
|
|
2012
|
|
Inc/
(Dec)
|
||||||||
Equity income, net
|
|
$
|
57,836
|
|
|
$
|
22,948
|
|
|
152
|
%
|
|
$
|
16,042
|
|
|
43
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2014
|
|
2013
|
|
Inc/
(Dec)
|
|
2012
|
|
Inc/
(Dec)
|
||||||||
NGL purchases
|
|
$
|
228,369
|
|
|
$
|
191,788
|
|
|
19
|
%
|
|
$
|
181,078
|
|
|
6
|
%
|
Residue purchases
|
|
178,701
|
|
|
155,559
|
|
|
15
|
%
|
|
143,962
|
|
|
8
|
%
|
|||
Other
|
|
30,886
|
|
|
16,938
|
|
|
82
|
%
|
|
11,039
|
|
|
53
|
%
|
|||
Cost of product
|
|
437,956
|
|
|
364,285
|
|
|
20
|
%
|
|
336,079
|
|
|
8
|
%
|
|||
Operation and maintenance
|
|
199,305
|
|
|
168,657
|
|
|
18
|
%
|
|
140,106
|
|
|
20
|
%
|
|||
Total cost of product and operation and maintenance expenses
|
|
$
|
637,261
|
|
|
$
|
532,942
|
|
|
20
|
%
|
|
$
|
476,185
|
|
|
12
|
%
|
•
|
a
$36.6 million
net increase in NGL purchases primarily at the DJ Basin complex, Hilight system, the DBM complex and Chipeta, partially offset by a decrease at the Red Desert complex;
|
•
|
a
$23.1 million
net increase in residue purchases, primarily driven by higher volumes at the Hilight system, the DJ Basin complex and Chipeta; and
|
•
|
a
$13.9 million
net increase in other items, primarily due to changes in imbalance positions at the DJ Basin complex.
|
•
|
an $11.6 million net increase in residue purchases primarily at the DJ Basin and the Red Desert complexes, partially offset by decreases at the Granger complex;
|
•
|
a $10.7 million net increase in NGL purchases primarily at the Red Desert complex, the Hilight system and the
DJ Basin complex, partially offset by decreases at Chipeta and the Granger complex; and
|
•
|
a $5.9 million net increase in other items, primarily due to gas compression expenses at the Granger complex and changes in imbalance positions primarily at the DJ Basin complex, and the Hilight and Hugoton systems.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2014
|
|
2013
|
|
Inc/
(Dec)
|
|
2012
|
|
Inc/
(Dec)
|
||||||||
General and administrative
|
|
$
|
34,242
|
|
|
$
|
29,751
|
|
|
15
|
%
|
|
$
|
99,212
|
|
|
(70
|
)%
|
Property and other taxes
|
|
25,353
|
|
|
23,244
|
|
|
9
|
%
|
|
19,688
|
|
|
18
|
%
|
|||
Depreciation, amortization and impairments
|
|
183,156
|
|
|
145,916
|
|
|
26
|
%
|
|
120,608
|
|
|
21
|
%
|
|||
Total general and administrative, depreciation and other expenses
|
|
$
|
242,751
|
|
|
$
|
198,911
|
|
|
22
|
%
|
|
$
|
239,508
|
|
|
(17
|
)%
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
2014
|
|
2013
|
|
Inc/
(Dec)
|
|
2012
|
|
Inc/
(Dec)
|
||||||||
Interest income on note receivable
|
$
|
16,900
|
|
|
$
|
16,900
|
|
|
—
|
%
|
|
$
|
16,900
|
|
|
—
|
%
|
Interest income – affiliates
|
$
|
16,900
|
|
|
$
|
16,900
|
|
|
—
|
%
|
|
$
|
16,900
|
|
|
—
|
%
|
Third parties
|
|
|
|
|
|
|
|
|
|
||||||||
Interest expense on long-term debt
|
$
|
(81,495
|
)
|
|
$
|
(59,293
|
)
|
|
37
|
%
|
|
$
|
(41,171
|
)
|
|
44
|
%
|
Amortization of debt issuance costs and commitment fees
|
(5,103
|
)
|
|
(4,449
|
)
|
|
15
|
%
|
|
(4,319
|
)
|
|
3
|
%
|
|||
Capitalized interest
|
9,832
|
|
|
11,945
|
|
|
(18
|
)%
|
|
6,196
|
|
|
93
|
%
|
|||
Affiliates
|
|
|
|
|
|
|
|
|
|
||||||||
Interest expense on note payable to Anadarko
(1)
|
—
|
|
|
—
|
|
|
—
|
%
|
|
(2,440
|
)
|
|
(100
|
)%
|
|||
Interest expense on affiliate balances
(2)
|
—
|
|
|
—
|
|
|
—
|
%
|
|
(326
|
)
|
|
(100
|
)%
|
|||
Interest expense
|
$
|
(76,766
|
)
|
|
$
|
(51,797
|
)
|
|
48
|
%
|
|
$
|
(42,060
|
)
|
|
23
|
%
|
(1)
|
In June 2012, the note payable to Anadarko was repaid in full. See
Note 12—Debt and Interest Expense
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(2)
|
Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures incurred in 2011 related to the construction of the Brasada complex and Lancaster plant. In the fourth quarter of 2012, we repaid the reimbursement payable to Anadarko associated with the construction of the Brasada complex and Lancaster plant. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2014
|
|
2013
|
|
Inc/
(Dec)
|
|
2012
|
|
Inc/
(Dec)
|
||||||||
Income before income taxes
|
|
$
|
392,585
|
|
|
$
|
287,798
|
|
|
36
|
%
|
|
$
|
169,957
|
|
|
69
|
%
|
Income tax (benefit) expense
|
|
2,027
|
|
|
2,355
|
|
|
(14
|
)%
|
|
20,690
|
|
|
(89
|
)%
|
|||
Effective tax rate
|
|
1
|
%
|
|
1
|
%
|
|
|
|
12
|
%
|
|
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2014
|
|
2013
|
|
Inc/
(Dec)
|
|
2012
|
|
Inc/
(Dec)
|
||||||||
Net income attributable to noncontrolling interests
|
|
$
|
14,025
|
|
|
$
|
10,816
|
|
|
30
|
%
|
|
$
|
14,890
|
|
|
(27
|
)%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages and per-unit amounts
|
|
2014
|
|
2013
|
|
Inc/
(Dec)
|
|
2012
|
|
Inc/
(Dec)
|
||||||||
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets
(1)
|
|
$
|
822,932
|
|
|
$
|
654,924
|
|
|
26
|
%
|
|
$
|
544,853
|
|
|
20
|
%
|
Adjusted gross margin for crude/NGL assets
(2)
|
|
73,714
|
|
|
15,274
|
|
|
NM
|
|
|
13,221
|
|
|
16
|
%
|
|||
Adjusted gross margin attributable to Western Gas Partners, LP
(3)
|
|
896,646
|
|
|
670,198
|
|
|
34
|
%
|
|
558,074
|
|
|
20
|
%
|
|||
Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets
(4)
|
|
0.65
|
|
|
0.56
|
|
|
16
|
%
|
|
0.53
|
|
|
6
|
%
|
|||
Adjusted gross margin per Bbl for crude/NGL assets
(5)
|
|
1.75
|
|
|
1.05
|
|
|
67
|
%
|
|
1.17
|
|
|
(10
|
)%
|
|||
Adjusted EBITDA attributable to Western Gas Partners, LP
(3)
|
|
645,969
|
|
|
457,773
|
|
|
41
|
%
|
|
377,929
|
|
|
21
|
%
|
|||
Distributable cash flow
(3)
|
|
531,136
|
|
|
380,529
|
|
|
40
|
%
|
|
309,945
|
|
|
23
|
%
|
(1)
|
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets is calculated as total revenues for natural gas assets less cost of product for natural gas assets plus distributions from our equity investments in Fort Union and Rendezvous, and excluding the noncontrolling interest owners’ 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 for crude/NGL assets less 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
|
|
2014
|
|
2013
|
|
2012
|
||||||
Acquisitions
|
|
$
|
1,902,520
|
|
|
$
|
716,985
|
|
|
$
|
611,719
|
|
|
|
|
|
|
|
|
||||||
Expansion capital expenditures
|
|
$
|
627,140
|
|
|
$
|
615,924
|
|
|
$
|
600,893
|
|
Maintenance capital expenditures
|
|
45,681
|
|
|
29,930
|
|
|
37,228
|
|
|||
Total capital expenditures
(1) (2) (3)
|
|
$
|
672,821
|
|
|
$
|
645,854
|
|
|
$
|
638,121
|
|
|
|
|
|
|
|
|
||||||
Capital incurred
(2) (4)
|
|
$
|
695,350
|
|
|
$
|
628,285
|
|
|
$
|
690,041
|
|
(1)
|
Maintenance capital expenditures for the
years ended December 31, 2014
,
2013
and 2012, are presented net of
$0.2 million
,
$0.6 million
and
zero
, respectively, of contributions in aid of construction costs from affiliates.
|
(2)
|
Includes the noncontrolling interest owners’ share of Chipeta’s capital expenditures, funded by contributions from the noncontrolling interest owners for all periods presented. For the
years ended December 31, 2014
,
2013
and 2012, included $9.8 million, $10.6 million and $6.8 million, respectively, of capitalized interest.
|
(3)
|
Capital expenditures for the year ended December 31, 2012, included $178.8 million of pre-acquisition capital for the Non-Operated Marcellus Interest systems.
|
(4)
|
Capital incurred for the
years ended December 31, 2013
and 2012, included $8.8 million and $160.9 million, respectively, of pre-acquisition capital incurred for the Non-Operated Marcellus Interest systems.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2014
|
|
2013
|
|
2012
|
||||||
Net cash provided by (used in):
|
|
|
|
|
|
|
||||||
Operating activities
|
|
$
|
534,807
|
|
|
$
|
448,201
|
|
|
$
|
338,047
|
|
Investing activities
|
|
(2,621,559
|
)
|
|
(1,652,995
|
)
|
|
(1,357,537
|
)
|
|||
Financing activities
|
|
2,053,078
|
|
|
885,541
|
|
|
1,212,912
|
|
|||
Net increase (decrease) in cash and cash equivalents
|
|
$
|
(33,674
|
)
|
|
$
|
(319,253
|
)
|
|
$
|
193,422
|
|
•
|
$1.5 billion of cash paid for the acquisition of DBM, net of $30.6 million of cash acquired;
|
•
|
$672.8 million
of capital expenditures, net of
$0.2 million
of contributions in aid of construction costs from affiliates, primarily related to projects at the DJ Basin complex, which include the continued construction of Train II at the Lancaster plant and compressor expansions;
|
•
|
$356.3 million of cash paid for the acquisition of the TEFR Interests;
|
•
|
$42.0 million
of cash paid related to FRP construction, which was completed in March 2014;
|
•
|
$22.9 million
of cash paid for equipment purchases from Anadarko;
|
•
|
$18.1 million
of distributions from equity investments in excess of cumulative earnings;
|
•
|
$10.5 million
of cash paid for a White Cliffs expansion project; and
|
•
|
$6.6 million
of cash paid related to TEP construction, which was completed in November 2013.
|
•
|
$646.5 million
of capital expenditures, net of $0.6 million of contributions in aid of construction costs from affiliates;
|
•
|
$465.5 million of cash paid for the Non-Operated Marcellus Interest acquisition;
|
•
|
$236.9 million of capital contributions to TEG, TEP and FRP for construction costs;
|
•
|
$134.6 million of cash paid for the Anadarko-Operated Marcellus Interest acquisition;
|
•
|
$78.1 million of cash paid for the Mont Belvieu JV acquisition;
|
•
|
$38.7 million of capital contributions to the Mont Belvieu JV to fund our share of construction costs for the fractionation trains completed in the fourth quarter of 2013;
|
•
|
$27.5 million of cash paid for the OTTCO acquisition;
|
•
|
$19.1 million of cash paid for a White Cliffs expansion project;
|
•
|
$11.2 million
of cash paid for equipment purchases from Anadarko; and
|
•
|
$4.4 million
of distributions from equity investments in excess of cumulative earnings.
|
•
|
$638.1 million
of capital expenditures;
|
•
|
$458.6 million of cash paid for the acquisition of the MGR assets;
|
•
|
$128.3 million of cash paid for the additional Chipeta interest;
|
•
|
$107.6 million of cash paid for capital contributions to TEP for construction costs and the initial investments in TEG and FRP; and
|
•
|
$24.7 million of cash paid for equipment purchases from Anadarko.
|
•
|
$750.0 million of proceeds from the issuance of Class C units to a subsidiary of Anadarko, all of which was used to fund a portion of the acquisition of DBM;
|
•
|
$603.0 million
of net proceeds from our November 2014 equity offering, including net proceeds from a capital contribution by our general partner, part of which was used to fund a portion of the acquisition of DBM;
|
•
|
$475.0 million
of borrowings to fund a portion of the acquisition of DBM;
|
•
|
$389.5 million of net proceeds from the 2044 Notes offering in March 2014, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of our 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 for general partnership purposes;
|
•
|
$100.0 million of net proceeds from the additional 2018 Notes offering in March 2014, after underwriting discounts, original issue premium and offering costs, part of which was used to repay a portion of our outstanding borrowings under our RCF;
|
•
|
$83.2 million
of net proceeds from sales of common units under the Continuous Offering Program (as defined and discussed in
Registered Securities
within this Item 7), 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; and
|
•
|
$0.4 million
of net proceeds from a capital contribution by our general partner after common units were issued in conjunction with the acquisition of the TEFR Interests.
|
•
|
$424.7 million of net proceeds from our May 2013 equity offering, including net proceeds from a capital contribution by our general partner, $245.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;
|
•
|
$299.0 million of borrowings to fund capital expenditures;
|
•
|
$273.7 million of net proceeds from our December 2013 equity offering, including net proceeds from a capital contribution by our general partner, $215.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;
|
•
|
$250.0 million
of borrowings to fund the Non-Operated Marcellus Interest acquisition;
|
•
|
$247.6 million of net proceeds from our 2018 Notes offering in August 2013, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of our outstanding borrowings under our RCF;
|
•
|
$133.5 million
of borrowings to fund the Anadarko-Operated Marcellus Interest acquisition;
|
•
|
$41.8 million of net proceeds from sales of common units under the Continuous Offering Program (as defined and discussed in
Registered Securities
within this Item 7), including net proceeds from capital contributions by our general partner;
|
•
|
$27.5 million of borrowings to fund the OTTCO acquisition; and
|
•
|
$0.5 million
of net proceeds from a capital contribution by our general partner after common units were issued in conjunction with the Non-Operated Marcellus Interest acquisition.
|
•
|
$511.3 million and $156.4 million of net proceeds from our 2022 Notes offerings in June 2012 and October 2012, respectively, after underwriting and original issue discounts, original issue premiums and offering costs;
|
•
|
$409.4 million of net proceeds from the issuance of common and general partner units sold in connection with the closing of the WGP IPO;
|
•
|
$299.0 million of borrowings to fund the acquisition of the MGR assets; and
|
•
|
$216.4 million of net proceeds from our June 2012 equity offering.
|
|
|
Obligations by Period
|
||||||||||||||||||||||||||
thousands
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
Thereafter
|
|
Total
|
||||||||||||||
Long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Principal
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
350,000
|
|
|
$
|
510,000
|
|
|
$
|
1,570,000
|
|
|
$
|
2,430,000
|
|
Interest
|
|
90,911
|
|
|
90,911
|
|
|
90,911
|
|
|
86,686
|
|
|
76,705
|
|
|
654,169
|
|
|
1,090,293
|
|
|||||||
Asset retirement obligations
|
|
1,212
|
|
|
1,865
|
|
|
—
|
|
|
—
|
|
|
1,342
|
|
|
104,673
|
|
|
109,092
|
|
|||||||
Capital expenditures
|
|
64,084
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
64,084
|
|
|||||||
Credit facility fees
|
|
2,400
|
|
|
560
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,960
|
|
|||||||
Environmental obligations
|
|
475
|
|
|
476
|
|
|
476
|
|
|
116
|
|
|
116
|
|
|
315
|
|
|
1,974
|
|
|||||||
Operating leases
|
|
338
|
|
|
303
|
|
|
157
|
|
|
34
|
|
|
—
|
|
|
—
|
|
|
832
|
|
|||||||
Total
|
|
$
|
159,420
|
|
|
$
|
94,115
|
|
|
$
|
91,544
|
|
|
$
|
436,836
|
|
|
$
|
588,163
|
|
|
$
|
2,329,157
|
|
|
$
|
3,699,235
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Donald R. Sinclair
|
|
Donald R. Sinclair
President and Chief Executive Officer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
|
/s/ Benjamin M. Fink
|
|
Benjamin M. Fink
Senior Vice President, Chief Financial Officer and Treasurer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands except per-unit amounts
|
|
2014
|
|
2013
|
|
2012
|
||||||
Revenues – affiliates
|
|
|
|
|
|
|
||||||
Gathering, processing and transportation of natural gas and natural gas liquids
|
|
$
|
394,870
|
|
|
$
|
306,810
|
|
|
$
|
249,997
|
|
Natural gas, natural gas liquids and condensate sales
|
|
570,047
|
|
|
496,848
|
|
|
436,423
|
|
|||
Other
|
|
5,078
|
|
|
1,868
|
|
|
1,606
|
|
|||
Total revenues – affiliates
|
|
969,995
|
|
|
805,526
|
|
|
688,026
|
|
|||
Revenues – third parties
|
|
|
|
|
|
|
||||||
Gathering, processing and transportation of natural gas and natural gas liquids
|
|
252,581
|
|
|
175,732
|
|
|
132,333
|
|
|||
Natural gas, natural gas liquids and condensate sales
|
|
42,807
|
|
|
44,396
|
|
|
71,916
|
|
|||
Other
|
|
8,380
|
|
|
4,109
|
|
|
2,201
|
|
|||
Total revenues – third parties
|
|
303,768
|
|
|
224,237
|
|
|
206,450
|
|
|||
Total revenues
|
|
1,273,763
|
|
|
1,029,763
|
|
|
894,476
|
|
|||
Equity income, net
(1)
|
|
57,836
|
|
|
22,948
|
|
|
16,042
|
|
|||
Operating expenses
|
|
|
|
|
|
|
||||||
Cost of product
(2)
|
|
437,956
|
|
|
364,285
|
|
|
336,079
|
|
|||
Operation and maintenance
(2)
|
|
199,305
|
|
|
168,657
|
|
|
140,106
|
|
|||
General and administrative
(2)
|
|
34,242
|
|
|
29,751
|
|
|
99,212
|
|
|||
Property and other taxes
|
|
25,353
|
|
|
23,244
|
|
|
19,688
|
|
|||
Depreciation, amortization and impairments
|
|
183,156
|
|
|
145,916
|
|
|
120,608
|
|
|||
Total operating expenses
|
|
880,012
|
|
|
731,853
|
|
|
715,693
|
|
|||
Operating income
|
|
451,587
|
|
|
320,858
|
|
|
194,825
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
(3)
|
|
(76,766
|
)
|
|
(51,797
|
)
|
|
(42,060
|
)
|
|||
Other income (expense), net
|
|
864
|
|
|
1,837
|
|
|
292
|
|
|||
Income before income taxes
|
|
392,585
|
|
|
287,798
|
|
|
169,957
|
|
|||
Income tax (benefit) expense
|
|
2,027
|
|
|
2,355
|
|
|
20,690
|
|
|||
Net income
|
|
390,558
|
|
|
285,443
|
|
|
149,267
|
|
|||
Net income attributable to noncontrolling interests
|
|
14,025
|
|
|
10,816
|
|
|
14,890
|
|
|||
Net income attributable to Western Gas Partners, LP
|
|
$
|
376,533
|
|
|
$
|
274,627
|
|
|
$
|
134,377
|
|
Limited partners’ interest in net income:
|
|
|
|
|
|
|
||||||
Net income attributable to Western Gas Partners, LP
|
|
$
|
376,533
|
|
|
$
|
274,627
|
|
|
$
|
134,377
|
|
Pre-acquisition net (income) loss allocated to Anadarko
|
|
956
|
|
|
(4,128
|
)
|
|
(27,391
|
)
|
|||
General partner interest in net (income) loss
(4)
|
|
(120,980
|
)
|
|
(69,633
|
)
|
|
(28,089
|
)
|
|||
Limited partners’ interest in net income
(4)
|
|
256,509
|
|
|
200,866
|
|
|
78,897
|
|
|||
Net income per common unit – basic
(5)
|
|
$
|
2.13
|
|
|
$
|
1.83
|
|
|
$
|
0.84
|
|
Net income per common unit – diluted
(5)
|
|
2.12
|
|
|
1.83
|
|
|
0.84
|
|
(1)
|
Income earned from equity investments is classified as affiliate. See
Note 1
.
|
(2)
|
Cost of product includes product purchases from Anadarko (as defined in
Note 1
) of
$114.0 million
,
$129.0 million
and
$145.3 million
for the
years ended December 31, 2014
,
2013
and
2012
, respectively. Operation and maintenance includes charges from Anadarko of
$58.9 million
,
$56.4 million
and
$51.2 million
for the
years ended December 31, 2014
,
2013
and
2012
, respectively. General and administrative includes charges from Anadarko of
$27.0 million
,
$23.4 million
and
$92.8 million
for the
years ended December 31, 2014
,
2013
and
2012
, respectively. See
Note 5
.
|
(3)
|
Includes affiliate (as defined in
Note 1
) interest expense of
zero
for each of the years ended December 31, 2014 and 2013, and
$2.8 million
for the year ended December 31, 2012. See
Note 12
.
|
(4)
|
Represents net income 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 per unit.
|
|
|
December 31,
|
||||||
thousands except number of units
|
|
2014
|
|
2013
|
||||
ASSETS
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
67,054
|
|
|
$
|
100,728
|
|
Accounts receivable, net
(1)
|
|
98,114
|
|
|
84,060
|
|
||
Other current assets
(2)
|
|
10,067
|
|
|
10,022
|
|
||
Total current assets
|
|
175,235
|
|
|
194,810
|
|
||
Note receivable – Anadarko
|
|
260,000
|
|
|
260,000
|
|
||
Property, plant and equipment
|
|
|
|
|
||||
Cost
|
|
5,424,699
|
|
|
4,239,100
|
|
||
Less accumulated depreciation
|
|
1,040,328
|
|
|
855,845
|
|
||
Net property, plant and equipment
|
|
4,384,371
|
|
|
3,383,255
|
|
||
Goodwill
|
|
384,387
|
|
|
105,336
|
|
||
Other intangible assets
|
|
884,857
|
|
|
53,606
|
|
||
Equity investments
|
|
634,492
|
|
|
593,400
|
|
||
Other assets
|
|
28,289
|
|
|
27,401
|
|
||
Total assets
|
|
$
|
6,751,631
|
|
|
$
|
4,617,808
|
|
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accounts and natural gas imbalance payables
(3)
|
|
$
|
29,104
|
|
|
$
|
39,589
|
|
Accrued ad valorem taxes
|
|
14,812
|
|
|
13,860
|
|
||
Accrued liabilities
(4)
|
|
158,655
|
|
|
137,011
|
|
||
Total current liabilities
|
|
202,571
|
|
|
190,460
|
|
||
Long-term debt
|
|
2,422,954
|
|
|
1,418,169
|
|
||
Deferred income taxes
|
|
4,171
|
|
|
37,998
|
|
||
Asset retirement obligations and other
|
|
110,069
|
|
|
79,145
|
|
||
Total long-term liabilities
|
|
2,537,194
|
|
|
1,535,312
|
|
||
Total liabilities
|
|
2,739,765
|
|
|
1,725,772
|
|
||
Equity and partners’ capital
|
|
|
|
|
||||
Common units (127,695,130 and 117,322,812 units issued and outstanding at December 31, 2014 and 2013, respectively)
|
|
3,119,714
|
|
|
2,431,193
|
|
||
Class C units (10,913,853 and zero units issued and outstanding at December 31, 2014 and 2013, respectively)
|
|
716,957
|
|
|
—
|
|
||
General partner units (2,583,068 and 2,394,345 units issued and outstanding at December 31, 2014 and 2013, respectively)
|
|
105,725
|
|
|
78,157
|
|
||
Net investment by Anadarko
|
|
—
|
|
|
312,092
|
|
||
Total partners’ capital
|
|
3,942,396
|
|
|
2,821,442
|
|
||
Noncontrolling interest
|
|
69,470
|
|
|
70,594
|
|
||
Total equity and partners’ capital
|
|
4,011,866
|
|
|
2,892,036
|
|
||
Total liabilities, equity and partners’ capital
|
|
$
|
6,751,631
|
|
|
$
|
4,617,808
|
|
(1)
|
Accounts receivable, net includes amounts receivable from affiliates (as defined in
Note 1
) of
$64.7 million
and
$47.9 million
as of
December 31, 2014
and
2013
, respectively.
|
(2)
|
Other current assets includes natural gas imbalance receivables from affiliates of
$0.2 million
and
$0.1 million
as of
December 31, 2014
and
2013
, respectively.
|
(3)
|
Accounts and natural gas imbalance payables includes amounts payable to affiliates of
$0.1 million
and
$2.3 million
as of
December 31, 2014
and
2013
, respectively.
|
(4)
|
Accrued liabilities includes amounts payable to affiliates of
zero
and
$0.1 million
as of
December 31, 2014
and
2013
, respectively.
|
|
|
Partners’ Capital
|
|
|
|
|
||||||||||||||||||
thousands
|
|
Net
Investment
by Anadarko
|
|
Common
Units
|
|
Class C Units
|
|
General
Partner
Units
|
|
Noncontrolling
Interests
|
|
Total
|
||||||||||||
Balance at December 31, 2011
|
|
$
|
362,573
|
|
|
$
|
1,495,253
|
|
|
$
|
—
|
|
|
$
|
31,729
|
|
|
$
|
120,724
|
|
|
$
|
2,010,279
|
|
Net income (loss)
|
|
27,391
|
|
|
78,897
|
|
|
—
|
|
|
28,089
|
|
|
14,890
|
|
|
149,267
|
|
||||||
Issuance of common and general partner units, net of offering expenses
|
|
—
|
|
|
613,188
|
|
|
—
|
|
|
12,689
|
|
|
—
|
|
|
625,877
|
|
||||||
Contributions from noncontrolling interest owners
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
29,108
|
|
|
29,108
|
|
||||||
Distributions to noncontrolling interest owners
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17,303
|
)
|
|
(17,303
|
)
|
||||||
Distributions to unitholders
|
|
—
|
|
|
(175,639
|
)
|
|
—
|
|
|
(22,211
|
)
|
|
—
|
|
|
(197,850
|
)
|
||||||
Acquisition from affiliates
|
|
(482,701
|
)
|
|
23,458
|
|
|
—
|
|
|
479
|
|
|
—
|
|
|
(458,764
|
)
|
||||||
Acquisition of additional 24% interest in Chipeta
(1)
|
|
—
|
|
|
(44,071
|
)
|
|
—
|
|
|
162
|
|
|
(77,195
|
)
|
|
(121,104
|
)
|
||||||
Contributions of equity-based compensation from Anadarko
(2)
|
|
—
|
|
|
84,971
|
|
|
—
|
|
|
2,086
|
|
|
—
|
|
|
87,057
|
|
||||||
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
299,833
|
|
|
(106,597
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
193,236
|
|
||||||
Net distributions to Anadarko of other assets
|
|
—
|
|
|
(15,002
|
)
|
|
—
|
|
|
(273
|
)
|
|
(21
|
)
|
|
(15,296
|
)
|
||||||
Elimination of net deferred tax liabilities
|
|
106,504
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
106,504
|
|
||||||
Other
|
|
—
|
|
|
2,608
|
|
|
—
|
|
|
2
|
|
|
455
|
|
|
3,065
|
|
||||||
Balance at December 31, 2012
|
|
$
|
313,600
|
|
|
$
|
1,957,066
|
|
|
$
|
—
|
|
|
$
|
52,752
|
|
|
$
|
70,658
|
|
|
$
|
2,394,076
|
|
Net income (loss)
|
|
4,128
|
|
|
200,866
|
|
|
—
|
|
|
69,633
|
|
|
10,816
|
|
|
285,443
|
|
||||||
Issuance of common and general partner units, net of offering expenses
|
|
—
|
|
|
724,811
|
|
|
—
|
|
|
15,775
|
|
|
—
|
|
|
740,586
|
|
||||||
Contributions from noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,247
|
|
|
2,247
|
|
||||||
Distributions to noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13,127
|
)
|
|
(13,127
|
)
|
||||||
Distributions to unitholders
|
|
—
|
|
|
(239,157
|
)
|
|
—
|
|
|
(59,944
|
)
|
|
—
|
|
|
(299,101
|
)
|
||||||
Acquisitions from affiliates
|
|
(255,635
|
)
|
|
(209,865
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(465,500
|
)
|
||||||
Contributions of equity-based compensation from Anadarko
(2)
|
|
—
|
|
|
2,865
|
|
|
—
|
|
|
58
|
|
|
—
|
|
|
2,923
|
|
||||||
Net pre-acquisition contributions from (distributions to) Anadarko
(3)
|
|
203,469
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
203,469
|
|
||||||
Net distributions to Anadarko of other assets
|
|
—
|
|
|
(5,738
|
)
|
|
—
|
|
|
(117
|
)
|
|
—
|
|
|
(5,855
|
)
|
||||||
Elimination of net deferred tax liabilities
|
|
46,530
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46,530
|
|
||||||
Other
|
|
—
|
|
|
345
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
345
|
|
||||||
Balance at December 31, 2013
|
|
$
|
312,092
|
|
|
$
|
2,431,193
|
|
|
$
|
—
|
|
|
$
|
78,157
|
|
|
$
|
70,594
|
|
|
$
|
2,892,036
|
|
Net income (loss)
|
|
(956
|
)
|
|
254,737
|
|
|
1,772
|
|
|
120,980
|
|
|
14,025
|
|
|
390,558
|
|
||||||
Issuance of common and general partner units, net of offering expenses
|
|
—
|
|
|
691,417
|
|
|
—
|
|
|
13,311
|
|
|
—
|
|
|
704,728
|
|
||||||
Issuance of Class C units
|
|
—
|
|
|
—
|
|
|
750,000
|
|
|
—
|
|
|
—
|
|
|
750,000
|
|
||||||
Beneficial conversion feature of Class C units
|
|
—
|
|
|
34,815
|
|
|
(34,815
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Distributions to noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15,149
|
)
|
|
(15,149
|
)
|
||||||
Distributions to unitholders
|
|
—
|
|
|
(302,049
|
)
|
|
—
|
|
|
(106,572
|
)
|
|
—
|
|
|
(408,621
|
)
|
||||||
Acquisitions from affiliates
|
|
(372,784
|
)
|
|
16,534
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(356,250
|
)
|
||||||
Contributions of equity-based compensation from Anadarko
(2)
|
|
—
|
|
|
3,104
|
|
|
—
|
|
|
63
|
|
|
—
|
|
|
3,167
|
|
||||||
Net pre-acquisition contributions from (distributions to) Anadarko
(3)
|
|
23,488
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23,488
|
|
||||||
Net distributions to Anadarko of other assets
|
|
—
|
|
|
(10,519
|
)
|
|
—
|
|
|
(214
|
)
|
|
—
|
|
|
(10,733
|
)
|
||||||
Elimination of net deferred tax liabilities
|
|
38,160
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
38,160
|
|
||||||
Other
|
|
—
|
|
|
482
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
482
|
|
||||||
Balance at December 31, 2014
|
|
$
|
—
|
|
|
$
|
3,119,714
|
|
|
$
|
716,957
|
|
|
$
|
105,725
|
|
|
$
|
69,470
|
|
|
$
|
4,011,866
|
|
(1)
|
See
Note 2
for a description of the acquisition of Anadarko’s then-remaining
24%
membership interest in Chipeta in August 2012. The
$43.9 million
decrease to partners’ capital resulting from the August 2012 Chipeta acquisition, together with net income attributable to Western Gas Partners, LP, totaled
$90.5 million
for the year ended
December 31, 2012
.
|
(2)
|
Associated with the Anadarko Incentive Plans for the years ended
December 31, 2014
,
2013
and
2012
and the Incentive Plan for the year ended
December 31, 2012
, as defined and described in
Note 1
and
Note 5
.
|
(3)
|
Includes deferred taxes on capitalized interest of
$0.3 million
and
$5.5 million
associated with the acquisition of the TEFR Interests (as defined and described in
Note 1
) for the years ended
December 31, 2014
and
2013
, respectively.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2014
|
|
2013
|
|
2012
|
||||||
Cash flows from operating activities
|
|
|
|
|
|
|
||||||
Net income
|
|
$
|
390,558
|
|
|
$
|
285,443
|
|
|
$
|
149,267
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
Depreciation, amortization and impairments
|
|
183,156
|
|
|
145,916
|
|
|
120,608
|
|
|||
Non-cash equity-based compensation expense
|
|
3,920
|
|
|
3,521
|
|
|
3,717
|
|
|||
Deferred income taxes
|
|
2,583
|
|
|
31,891
|
|
|
30,109
|
|
|||
Debt-related amortization and other items, net
|
|
2,736
|
|
|
2,449
|
|
|
2,319
|
|
|||
Equity income, net
(1)
|
|
(57,836
|
)
|
|
(22,948
|
)
|
|
(16,042
|
)
|
|||
Distributions from equity investment earnings
(1)
|
|
62,967
|
|
|
17,698
|
|
|
20,660
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
|
||||||
(Increase) decrease in accounts receivable, net
|
|
(4,217
|
)
|
|
(34,019
|
)
|
|
22,916
|
|
|||
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net
|
|
(52,530
|
)
|
|
21,952
|
|
|
5,045
|
|
|||
Change in other items, net
|
|
3,470
|
|
|
(3,702
|
)
|
|
(552
|
)
|
|||
Net cash provided by operating activities
|
|
534,807
|
|
|
448,201
|
|
|
338,047
|
|
|||
Cash flows from investing activities
|
|
|
|
|
|
|
||||||
Capital expenditures
|
|
(673,004
|
)
|
|
(646,471
|
)
|
|
(638,121
|
)
|
|||
Contributions in aid of construction costs from affiliates
|
|
183
|
|
|
617
|
|
|
—
|
|
|||
Acquisitions from affiliates
|
|
(379,193
|
)
|
|
(476,711
|
)
|
|
(611,719
|
)
|
|||
Acquisitions from third parties
|
|
(1,523,327
|
)
|
|
(240,274
|
)
|
|
—
|
|
|||
Investments in equity affiliates
|
|
(64,278
|
)
|
|
(294,693
|
)
|
|
(108,457
|
)
|
|||
Distributions from equity investments in excess of cumulative earnings
(1)
|
|
18,055
|
|
|
4,438
|
|
|
—
|
|
|||
Proceeds from the sale of assets to affiliates
|
|
—
|
|
|
85
|
|
|
760
|
|
|||
Proceeds from the sale of assets to third parties
|
|
5
|
|
|
14
|
|
|
—
|
|
|||
Net cash used in investing activities
|
|
(2,621,559
|
)
|
|
(1,652,995
|
)
|
|
(1,357,537
|
)
|
|||
Cash flows from financing activities
|
|
|
|
|
|
|
||||||
Borrowings, net of debt issuance costs
|
|
1,646,878
|
|
|
957,503
|
|
|
1,041,648
|
|
|||
Repayments of debt
|
|
(650,000
|
)
|
|
(710,000
|
)
|
|
(549,000
|
)
|
|||
Increase (decrease) in outstanding checks
|
|
1,693
|
|
|
(1,763
|
)
|
|
1,800
|
|
|||
Proceeds from the issuance of common and general partner units, net of offering expenses
|
|
704,489
|
|
|
740,825
|
|
|
625,877
|
|
|||
Proceeds from the issuance of Class C units
|
|
750,000
|
|
|
—
|
|
|
—
|
|
|||
Distributions to unitholders
|
|
(408,621
|
)
|
|
(299,101
|
)
|
|
(197,850
|
)
|
|||
Contributions from noncontrolling interest owners
|
|
—
|
|
|
2,247
|
|
|
29,108
|
|
|||
Distributions to noncontrolling interest owners
|
|
(15,149
|
)
|
|
(13,127
|
)
|
|
(17,303
|
)
|
|||
Net contributions from Anadarko
|
|
23,788
|
|
|
208,957
|
|
|
278,632
|
|
|||
Net cash provided by financing activities
|
|
2,053,078
|
|
|
885,541
|
|
|
1,212,912
|
|
|||
Net increase (decrease) in cash and cash equivalents
|
|
(33,674
|
)
|
|
(319,253
|
)
|
|
193,422
|
|
|||
Cash and cash equivalents at beginning of period
|
|
100,728
|
|
|
419,981
|
|
|
226,559
|
|
|||
Cash and cash equivalents at end of period
|
|
$
|
67,054
|
|
|
$
|
100,728
|
|
|
$
|
419,981
|
|
Supplemental disclosures
|
|
|
|
|
|
|
||||||
Net distributions to Anadarko of other assets
|
|
$
|
10,733
|
|
|
$
|
5,855
|
|
|
$
|
15,296
|
|
Interest paid, net of capitalized interest
|
|
67,648
|
|
|
47,098
|
|
|
28,042
|
|
|||
Taxes paid (reimbursements received)
|
|
(90
|
)
|
|
552
|
|
|
495
|
|
|||
Capital lease asset transfer
(2)
|
|
4,833
|
|
|
—
|
|
|
—
|
|
(1)
|
Income earned on, distributions from and contributions to equity investments are classified as affiliate. See
Note 1
.
|
(2)
|
For the
year ended December 31, 2014
, represents transfers of
$4.6 million
from other long-term assets, associated with the capital lease components of a processing agreement. See
Note 7
.
|
|
|
Owned and
Operated
|
|
Operated
Interests
|
|
Non-Operated
Interests
|
|
Equity Interests
|
||||
Natural gas gathering systems
|
|
14
|
|
|
1
|
|
|
5
|
|
|
2
|
|
Natural gas treating facilities
|
|
8
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Natural gas processing facilities
|
|
13
|
|
|
3
|
|
|
—
|
|
|
2
|
|
NGL pipelines
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Natural gas pipelines
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Oil pipeline
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
thousands except unit and percent amounts
|
|
Acquisition
Date
|
|
Percentage
Acquired |
|
Borrowings
|
|
Cash
On Hand
|
|
Common
Units Issued to Anadarko
|
|
Class C
Units Issued to Anadarko
|
|
GP Units
Issued
|
||||||||
MGR
(1)
|
|
01/13/2012
|
|
100
|
%
|
|
$
|
299,000
|
|
|
$
|
159,587
|
|
|
632,783
|
|
|
—
|
|
|
12,914
|
|
Chipeta
(2)
|
|
08/01/2012
|
|
24
|
%
|
|
—
|
|
|
128,250
|
|
|
151,235
|
|
|
—
|
|
|
3,086
|
|
||
Non-Operated Marcellus Interest
(3)
|
|
03/01/2013
|
|
33.75
|
%
|
|
250,000
|
|
|
215,500
|
|
|
449,129
|
|
|
—
|
|
|
—
|
|
||
Anadarko-Operated Marcellus Interest
(4)
|
|
03/08/2013
|
|
33.75
|
%
|
|
133,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
Mont Belvieu JV
(5)
|
|
06/05/2013
|
|
25
|
%
|
|
—
|
|
|
78,129
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
OTTCO
(6)
|
|
09/03/2013
|
|
100
|
%
|
|
27,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
TEFR Interests
(7)
|
|
03/03/2014
|
|
Various
(7)
|
|
|
350,000
|
|
|
6,250
|
|
|
308,490
|
|
|
—
|
|
|
—
|
|
||
DBM
(8)
|
|
11/25/2014
|
|
100
|
%
|
|
475,000
|
|
|
298,327
|
|
|
—
|
|
|
10,913,853
|
|
|
—
|
|
(1)
|
The assets acquired from Anadarko consisted of (i) the “Red Desert complex,” which is located in the greater Green River Basin in southwestern Wyoming, and includes the Patrick Draw processing plant, the Red Desert processing plant, gathering lines, and related facilities, (ii) a
22%
interest in Rendezvous, which owns a gathering system serving the Jonah and Pinedale Anticline fields in southwestern Wyoming, and (iii) certain additional midstream assets and equipment. These assets are collectively referred to as the “MGR assets” and the acquisition as the “MGR acquisition.”
|
(2)
|
The Partnership acquired Anadarko’s additional Chipeta interest (as described in
Note 1
). The Partnership received distributions related to the additional interest beginning July 1, 2012. This transaction brought the Partnership’s total membership interest in Chipeta to
75%
. The remaining
25%
membership interest in Chipeta held by a third-party member is reflected as noncontrolling interests in the consolidated financial statements for all periods presented.
|
(3)
|
The Partnership acquired Anadarko’s 33.75% interest (non-operated) (the “Non-Operated Marcellus Interest”) in the Liberty and Rome gas gathering systems (the “Non-Operated Marcellus Interest systems”), serving production from the Marcellus shale in North-central Pennsylvania. In connection with the issuance of the common units, the Partnership’s general partner purchased
9,166
general partner units for consideration of
$0.5 million
.
|
(4)
|
The Partnership acquired a 33.75% interest (the “Anadarko-Operated Marcellus Interest”) in each of the Larry’s Creek, Seely and Warrensville gas gathering systems (the “Anadarko-Operated Marcellus Interest systems”), which are operated by Anadarko and serve production from the Marcellus shale in North-central Pennsylvania, from a third party. During the third quarter of 2013, the Partnership recorded a
$1.1 million
decrease in the assets acquired and liabilities assumed in the acquisition, representing the final purchase price allocation.
|
(5)
|
The Partnership acquired a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own
two
fractionation trains located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting.
|
(6)
|
The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming.
|
(7)
|
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’s general partner purchased
6,296
general partner units in exchange for the general partner’s proportionate capital contribution of
$0.4 million
.
|
(8)
|
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 serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico. These assets are referred to collectively as the “DBM complex.” See
Note 4
for a discussion of the Class C units
.
|
thousands
|
|
|
||
Current assets
|
|
$
|
46,358
|
|
Property, plant and equipment
|
|
440,971
|
|
|
Goodwill
|
|
279,051
|
|
|
Other intangible assets
|
|
835,566
|
|
|
Accounts payables
|
|
(13,064
|
)
|
|
Accrued liabilities
|
|
(24,824
|
)
|
|
Deferred income taxes
|
|
(1,450
|
)
|
|
Asset retirement obligations and other
|
|
(8,649
|
)
|
|
Total purchase price
|
|
$
|
1,553,959
|
|
|
|
Year Ended December 31,
|
||||||
thousands except per-unit amounts
|
|
2014
|
|
2013
|
||||
Revenues
|
|
$
|
1,397,030
|
|
|
$
|
1,107,030
|
|
Net income
|
|
332,420
|
|
|
239,382
|
|
||
Net income attributable to Western Gas Partners, LP
|
|
318,395
|
|
|
228,566
|
|
||
Net income per common unit – basic and diluted
|
|
1.34
|
|
|
1.12
|
|
thousands except per-unit amounts
Quarters Ended
|
|
Total Quarterly
Distribution
per Unit
|
|
Total Quarterly
Cash Distribution
|
|
Date of
Distribution
|
|||||
2012
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.460
|
|
|
$
|
46,053
|
|
|
May 2012
|
|
June 30
|
|
0.480
|
|
|
52,425
|
|
|
August 2012
|
|||
September 30
|
|
0.500
|
|
|
56,346
|
|
|
November 2012
|
|||
December 31
|
|
0.520
|
|
|
65,657
|
|
|
February 2013
|
|||
2013
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.540
|
|
|
$
|
70,143
|
|
|
May 2013
|
|
June 30
|
|
0.560
|
|
|
79,315
|
|
|
August 2013
|
|||
September 30
|
|
0.580
|
|
|
83,986
|
|
|
November 2013
|
|||
December 31
|
|
0.600
|
|
|
92,609
|
|
|
February 2014
|
|||
2014
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.625
|
|
|
$
|
98,749
|
|
|
May 2014
|
|
June 30
|
|
0.650
|
|
|
105,655
|
|
|
August 2014
|
|||
September 30
|
|
0.675
|
|
|
111,608
|
|
|
November 2014
|
|||
December 31
(1)
|
|
0.700
|
|
|
126,044
|
|
|
February 2015
|
(1)
|
On
January 22, 2015
, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of
$0.700
per unit, or
$126.0 million
in aggregate, including incentive distributions, but excluding distributions on Class C units (see
Class C unit distributions
below). The cash distribution was paid on
February 12, 2015
, to unitholders of record at the close of business on
February 2, 2015
.
|
|
|
Total Quarterly Distribution
Target Amount
|
|
Marginal Percentage
Interest in Distributions
|
||
|
|
|
Unitholders
|
|
General Partner
|
|
Minimum quarterly distribution
|
|
$0.300
|
|
98.1%
|
|
1.9%
|
First target distribution
|
|
up to $0.345
|
|
98.1%
|
|
1.9%
|
Second target distribution
|
|
above $0.345 up to $0.375
|
|
85.1%
|
|
14.9%
|
Third target distribution
|
|
above $0.375 up to $0.450
|
|
75.1%
|
|
24.9%
|
Thereafter
|
|
above $0.450
|
|
50.1%
|
|
49.9%
|
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
|
||||||||
June 2012 equity offering
|
5,000,000
|
|
|
102,041
|
|
|
$
|
43.88
|
|
|
$
|
7,468
|
|
|
$
|
216,409
|
|
May 2013 equity offering
(2)
|
7,015,000
|
|
|
143,163
|
|
|
61.18
|
|
|
13,203
|
|
|
424,733
|
|
|||
December 2013 equity offering
(3)
|
4,800,000
|
|
|
97,959
|
|
|
61.51
|
|
|
9,447
|
|
|
291,827
|
|
|||
Continuous Offering Program - 2013
(4)
|
685,735
|
|
|
13,996
|
|
|
60.84
|
|
|
965
|
|
|
41,603
|
|
|||
Continuous Offering Program - 2014
(5)
|
1,133,384
|
|
|
23,132
|
|
|
73.48
|
|
|
1,738
|
|
|
83,245
|
|
|||
November 2014 equity offering
(6)
|
8,620,153
|
|
|
153,061
|
|
|
70.85
|
|
|
18,583
|
|
|
602,999
|
|
(1)
|
Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution.
|
(2)
|
Includes the issuance of
915,000
common units pursuant to the full exercise of the underwriters’ over-allotment option.
|
(3)
|
Includes the issuance of
300,000
common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise (including the general partner’s proportionate capital contribution) were
$18.1 million
.
|
(4)
|
Represents common and general partner units issued during the year ended December 31, 2013, pursuant to the Partnership’s registration statement filed with the U.S. Securities and Exchange Commission (“SEC”) in August 2012 authorizing the issuance of up to an aggregate of
$125.0 million
of common units (the “Continuous Offering Program”). Gross proceeds generated (including the general partner’s proportionate capital contributions) during the year ended December 31, 2013, were
$42.6 million
. The price per unit in the table above represents an average price for all issuances under the Continuous Offering Program during 2013.
|
(5)
|
Represents common and general partner units issued during the
year ended December 31, 2014
, under the Continuous Offering Program. 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 Continuous Offering Program during the
year ended December 31, 2014
. As of
December 31, 2014
, the Partnership had used all the capacity to issue common units under this registration statement.
|
(6)
|
Includes the issuance of
1,120,153
common units pursuant to the partial exercise of the underwriters’ over-allotment option. Net proceeds from this partial exercise were
$77.0 million
. Beginning with this partial exercise, the Partnership’s general partner elected not to make a corresponding capital contribution to maintain the general partner’s
2.0%
interest in the Partnership. See
Note 3
.
|
|
|
Common
Units
|
|
Class C Units
|
|
General
Partner Units
|
|
Total
|
||||
Balance at December 31, 2012
|
|
104,660,553
|
|
|
—
|
|
|
2,135,930
|
|
|
106,796,483
|
|
Non-Operated Marcellus Interest acquisition
|
|
449,129
|
|
|
—
|
|
|
9,166
|
|
|
458,295
|
|
Long-Term Incentive Plan awards
|
|
12,395
|
|
|
—
|
|
|
253
|
|
|
12,648
|
|
May 2013 equity offering
|
|
7,015,000
|
|
|
—
|
|
|
143,163
|
|
|
7,158,163
|
|
Continuous Offering Program
|
|
685,735
|
|
|
—
|
|
|
13,996
|
|
|
699,731
|
|
December 2013 equity offering
|
|
4,500,000
|
|
|
—
|
|
|
91,837
|
|
|
4,591,837
|
|
Balance at December 31, 2013
|
|
117,322,812
|
|
|
—
|
|
|
2,394,345
|
|
|
119,717,157
|
|
December 2013 equity offering
|
|
300,000
|
|
|
—
|
|
|
6,122
|
|
|
306,122
|
|
Long-Term Incentive Plan awards
|
|
10,291
|
|
|
—
|
|
|
112
|
|
|
10,403
|
|
TEFR Interests acquisition
|
|
308,490
|
|
|
—
|
|
|
6,296
|
|
|
314,786
|
|
Continuous Offering Program
|
|
1,133,384
|
|
|
—
|
|
|
23,132
|
|
|
1,156,516
|
|
November 2014 equity offering
|
|
8,620,153
|
|
|
—
|
|
|
153,061
|
|
|
8,773,214
|
|
Class C unit issuance
|
|
—
|
|
|
10,913,853
|
|
|
—
|
|
|
10,913,853
|
|
Balance at December 31, 2014
|
|
127,695,130
|
|
|
10,913,853
|
|
|
2,583,068
|
|
|
141,192,051
|
|
|
Year Ended December 31,
|
||||||||||
thousands except per-unit amounts
|
2014
|
|
2013
|
|
2012
|
||||||
Net income attributable to Western Gas Partners, LP
|
$
|
376,533
|
|
|
$
|
274,627
|
|
|
$
|
134,377
|
|
Pre-acquisition net (income) loss allocated to Anadarko
|
956
|
|
|
(4,128
|
)
|
|
(27,391
|
)
|
|||
General partner interest in net (income) loss
|
(120,980
|
)
|
|
(69,633
|
)
|
|
(28,089
|
)
|
|||
Limited partners’ interest in net income
|
256,509
|
|
|
200,866
|
|
|
78,897
|
|
|||
Net income allocable to common units
|
254,737
|
|
|
200,866
|
|
|
78,897
|
|
|||
Net income allocable to Class C units
|
1,772
|
|
|
—
|
|
|
—
|
|
|||
Limited partners’ interest in net income
|
$
|
256,509
|
|
|
$
|
200,866
|
|
|
$
|
78,897
|
|
Net income per unit
|
|
|
|
|
|
||||||
Common units - basic
|
$
|
2.13
|
|
|
$
|
1.83
|
|
|
$
|
0.84
|
|
Common units – diluted
|
2.12
|
|
|
1.83
|
|
|
0.84
|
|
|||
Weighted-average units outstanding
|
|
|
|
|
|
||||||
Common units – basic
|
119,822
|
|
|
109,872
|
|
|
93,936
|
|
|||
Class C units
|
1,106
|
|
|
—
|
|
|
—
|
|
|||
Common units – diluted
|
120,928
|
|
|
109,872
|
|
|
93,936
|
|
per barrel except natural gas
|
|
2015
|
|
2016
|
|||||||
Ethane
|
|
$
|
18.41
|
|
−
|
23.41
|
|
|
$
|
23.11
|
|
Propane
|
|
47.08
|
|
−
|
52.99
|
|
|
52.90
|
|
||
Isobutane
|
|
62.09
|
|
−
|
74.02
|
|
|
73.89
|
|
||
Normal butane
|
|
54.62
|
|
−
|
65.04
|
|
|
64.93
|
|
||
Natural gasoline
|
|
72.88
|
|
−
|
81.82
|
|
|
81.68
|
|
||
Condensate
|
|
76.47
|
|
−
|
81.82
|
|
|
81.68
|
|
||
Natural gas (per MMBtu)
|
|
4.66
|
|
−
|
5.96
|
|
|
4.87
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2014
|
|
2013
|
|
2012
|
||||||
Gains (losses) on commodity price swap agreements related to sales:
(1)
|
|
|
|
|
|
|
||||||
Natural gas sales
|
|
$
|
9,494
|
|
|
$
|
21,382
|
|
|
$
|
37,665
|
|
Natural gas liquids sales
|
|
113,866
|
|
|
102,076
|
|
|
66,260
|
|
|||
Total
|
|
123,360
|
|
|
123,458
|
|
|
103,925
|
|
|||
Losses on commodity price swap agreements related to purchases
(2)
|
|
(68,492
|
)
|
|
(85,294
|
)
|
|
(89,710
|
)
|
|||
Net gains (losses) on commodity price swap agreements
|
|
$
|
54,868
|
|
|
$
|
38,164
|
|
|
$
|
14,215
|
|
(1)
|
Reported in affiliate natural gas, natural gas liquids and condensate sales in the consolidated statements of income in the period in which the related sale is recorded.
|
(2)
|
Reported in cost of product in the consolidated statements of income in the period in which the related purchase is recorded.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2014
|
|
2013
|
|
2012
|
||||||
General and administrative expenses
|
|
$
|
20,249
|
|
|
$
|
16,882
|
|
|
$
|
14,904
|
|
Public company expenses
|
|
8,006
|
|
|
7,152
|
|
|
6,830
|
|
|||
Total reimbursement
|
|
$
|
28,255
|
|
|
$
|
24,034
|
|
|
$
|
21,734
|
|
|
2014
|
|
2013
|
|
2012
|
|||||||||||||||
|
Weighted-Average Grant-Date Fair Value
|
|
Units
|
|
Weighted-Average Grant-Date Fair Value
|
|
Units
|
|
Weighted-Average Grant-Date Fair Value
|
|
Units
|
|||||||||
Phantom units outstanding at beginning of year
|
$
|
49.47
|
|
|
16,844
|
|
|
$
|
41.77
|
|
|
25,619
|
|
|
$
|
33.92
|
|
|
23,978
|
|
Vested
|
49.55
|
|
|
(13,122
|
)
|
|
41.28
|
|
|
(14,695
|
)
|
|
33.20
|
|
|
(14,260
|
)
|
|||
Granted
|
68.14
|
|
|
5,800
|
|
|
62.49
|
|
|
5,920
|
|
|
45.91
|
|
|
15,901
|
|
|||
Phantom units outstanding at end of year
|
60.74
|
|
|
9,522
|
|
|
49.47
|
|
|
16,844
|
|
|
41.77
|
|
|
25,619
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|
2014
|
|
2013
|
|
2012
|
||||||||||||
thousands
|
|
Purchases
|
|
Sales
|
||||||||||||||||||||
Cash consideration
|
|
$
|
22,943
|
|
|
$
|
11,211
|
|
|
$
|
24,705
|
|
|
$
|
—
|
|
|
$
|
85
|
|
|
$
|
760
|
|
Net carrying value
|
|
12,210
|
|
|
5,309
|
|
|
8,009
|
|
|
—
|
|
|
38
|
|
|
393
|
|
||||||
Partners’ capital adjustment
|
|
$
|
10,733
|
|
|
$
|
5,902
|
|
|
$
|
16,696
|
|
|
$
|
—
|
|
|
$
|
47
|
|
|
$
|
367
|
|
|
|
Year ended December 31,
|
||||||||||
thousands
|
|
2014
|
|
2013
|
|
2012
|
||||||
Revenues
(1)
|
|
$
|
969,995
|
|
|
$
|
805,526
|
|
|
$
|
688,026
|
|
Equity income, net
(1)
|
|
57,836
|
|
|
22,948
|
|
|
16,042
|
|
|||
Cost of product
(1)
|
|
114,000
|
|
|
129,045
|
|
|
145,250
|
|
|||
Operation and maintenance
(2)
|
|
58,884
|
|
|
56,435
|
|
|
51,237
|
|
|||
General and administrative
(3)
|
|
26,989
|
|
|
23,354
|
|
|
92,847
|
|
|||
Operating expenses
|
|
199,873
|
|
|
208,834
|
|
|
289,334
|
|
|||
Interest income
(4)
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
(5)
|
|
—
|
|
|
—
|
|
|
2,766
|
|
|||
Distributions to unitholders
(6)
|
|
234,024
|
|
|
169,150
|
|
|
98,280
|
|
|||
Contributions from noncontrolling interest owners
(7)
|
|
—
|
|
|
—
|
|
|
12,588
|
|
|||
Distributions to noncontrolling interest owners
(7)
|
|
—
|
|
|
—
|
|
|
6,528
|
|
(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
,
WGP LTIP and Anadarko Incentive Plans
, and
The Incentive Plan
within this
Note 5
).
|
(4)
|
Represents interest income recognized on the note receivable from Anadarko.
|
(5)
|
For the year ended December 31, 2012, includes interest expense recognized on the note payable to Anadarko (see
Note 12
) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada complex and Lancaster plant. The Partnership repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko associated with the construction of the Brasada complex and Lancaster plant in the fourth quarter of 2012.
|
(6)
|
Represents distributions paid under the partnership agreement (see
Note 3
and
Note 4
).
|
(7)
|
As described in
Note 2
, the Partnership acquired the additional Chipeta interest on August 1, 2012, and accounted for the acquisition on a prospective basis. As such, contributions from noncontrolling interest owners and distributions to noncontrolling interest owners subsequent to the acquisition date no longer reflect contributions from or distributions to Anadarko.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2014
|
|
2013
|
|
2012
|
||||||
Current income tax expense (benefit)
|
|
|
|
|
|
|
||||||
Federal income tax expense (benefit)
|
|
$
|
(625
|
)
|
|
$
|
(30,176
|
)
|
|
$
|
(7,576
|
)
|
State income tax expense (benefit)
|
|
69
|
|
|
640
|
|
|
(1,843
|
)
|
|||
Total current income tax expense (benefit)
|
|
(556
|
)
|
|
(29,536
|
)
|
|
(9,419
|
)
|
|||
Deferred income tax expense (benefit)
|
|
|
|
|
|
|
||||||
Federal income tax expense (benefit)
|
|
171
|
|
|
32,930
|
|
|
22,324
|
|
|||
State income tax expense (benefit)
|
|
2,412
|
|
|
(1,039
|
)
|
|
7,785
|
|
|||
Total deferred income tax expense (benefit)
|
|
2,583
|
|
|
31,891
|
|
|
30,109
|
|
|||
Total income tax expense
|
|
$
|
2,027
|
|
|
$
|
2,355
|
|
|
$
|
20,690
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands except percentages
|
|
2014
|
|
2013
|
|
2012
|
||||||
Income before income taxes
|
|
$
|
392,585
|
|
|
$
|
287,798
|
|
|
$
|
169,957
|
|
Statutory tax rate
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Tax computed at statutory rate
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Adjustments resulting from:
|
|
|
|
|
|
|
||||||
Federal taxes on income attributable to Partnership assets pre-acquisition
|
|
(454
|
)
|
|
3,090
|
|
|
17,226
|
|
|||
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit)
|
|
—
|
|
|
624
|
|
|
2,206
|
|
|||
Texas margin tax expense (benefit)
|
|
2,481
|
|
|
(1,359
|
)
|
|
1,258
|
|
|||
Income tax expense
|
|
$
|
2,027
|
|
|
$
|
2,355
|
|
|
$
|
20,690
|
|
Effective tax rate
|
|
1
|
%
|
|
1
|
%
|
|
12
|
%
|
|
|
December 31,
|
||||||
thousands
|
|
2014
|
|
2013
|
||||
Credit carryforwards
|
|
$
|
14
|
|
|
$
|
14
|
|
Net current deferred income tax assets
|
|
14
|
|
|
14
|
|
||
Depreciable property
|
|
(3,240
|
)
|
|
(38,528
|
)
|
||
Credit carryforwards
|
|
512
|
|
|
527
|
|
||
Other intangible assets
|
|
(1,450
|
)
|
|
—
|
|
||
Other
|
|
7
|
|
|
3
|
|
||
Net long-term deferred income tax liabilities
|
|
(4,171
|
)
|
|
(37,998
|
)
|
||
Total net deferred income tax liabilities
|
|
$
|
(4,157
|
)
|
|
$
|
(37,984
|
)
|
|
|
|
|
December 31,
|
||||||
thousands
|
|
Estimated Useful Life
|
|
2014
|
|
2013
|
||||
Land
|
|
n/a
|
|
$
|
2,839
|
|
|
$
|
2,584
|
|
Gathering systems
|
|
3 to 47 years
|
|
4,790,974
|
|
|
3,673,008
|
|
||
Pipelines and equipment
|
|
15 to 45 years
|
|
151,107
|
|
|
146,008
|
|
||
Assets under construction
|
|
n/a
|
|
464,507
|
|
|
405,633
|
|
||
Other
|
|
3 to 40 years
|
|
15,272
|
|
|
11,867
|
|
||
Total property, plant and equipment
|
|
|
|
5,424,699
|
|
|
4,239,100
|
|
||
Accumulated depreciation
|
|
|
|
1,040,328
|
|
|
855,845
|
|
||
Net property, plant and equipment
|
|
|
|
$
|
4,384,371
|
|
|
$
|
3,383,255
|
|
|
|
December 31,
|
||||||
thousands
|
|
2014
|
|
2013
|
||||
Gross carrying amount
|
|
$
|
892,555
|
|
|
$
|
56,988
|
|
Accumulated amortization
|
|
(7,698
|
)
|
|
(3,382
|
)
|
||
Other intangible assets
|
|
$
|
884,857
|
|
|
$
|
53,606
|
|
|
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, 2012
|
$
|
23,453
|
|
|
$
|
17,567
|
|
|
$
|
65,110
|
|
|
$
|
—
|
|
|
$
|
9,033
|
|
|
$
|
80,737
|
|
|
$
|
23,866
|
|
|
$
|
219,766
|
|
Initial investment
|
—
|
|
|
—
|
|
|
—
|
|
|
78,129
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
78,129
|
|
||||||||
Investment earnings (loss), net of amortization
|
6,273
|
|
|
9,681
|
|
|
2,088
|
|
|
5,690
|
|
|
93
|
|
|
(776
|
)
|
|
(101
|
)
|
|
22,948
|
|
||||||||
Contributions
|
16
|
|
|
19,087
|
|
|
—
|
|
|
37,309
|
|
|
6,732
|
|
|
108,969
|
|
|
105,547
|
|
|
277,660
|
|
||||||||
Capitalized interest
|
—
|
|
|
—
|
|
|
—
|
|
|
1,352
|
|
|
791
|
|
|
8,801
|
|
|
6,089
|
|
|
17,033
|
|
||||||||
Distributions
|
(4,570
|
)
|
|
(9,099
|
)
|
|
(4,029
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17,698
|
)
|
||||||||
Distributions in excess of cumulative earnings
(8)
|
—
|
|
|
(2,197
|
)
|
|
(2,241
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,438
|
)
|
||||||||
Balance at December 31, 2013
|
$
|
25,172
|
|
|
$
|
35,039
|
|
|
$
|
60,928
|
|
|
$
|
122,480
|
|
|
$
|
16,649
|
|
|
$
|
197,731
|
|
|
$
|
135,401
|
|
|
$
|
593,400
|
|
Investment earnings (loss), net of amortization
|
6,344
|
|
|
11,912
|
|
|
1,729
|
|
|
29,029
|
|
|
650
|
|
|
6,108
|
|
|
2,064
|
|
|
57,836
|
|
||||||||
Contributions
|
—
|
|
|
10,456
|
|
|
—
|
|
|
3,957
|
|
|
352
|
|
|
6,623
|
|
|
42,033
|
|
|
63,421
|
|
||||||||
Capitalized interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
857
|
|
|
857
|
|
||||||||
Distributions
|
(5,583
|
)
|
|
(11,330
|
)
|
|
(3,669
|
)
|
|
(34,129
|
)
|
|
(523
|
)
|
|
(5,622
|
)
|
|
(2,111
|
)
|
|
(62,967
|
)
|
||||||||
Distributions in excess of cumulative earnings
(8)
|
—
|
|
|
(1,762
|
)
|
|
(2,652
|
)
|
|
—
|
|
|
(338
|
)
|
|
(6,047
|
)
|
|
(7,256
|
)
|
|
(18,055
|
)
|
||||||||
Balance at December 31, 2014
|
$
|
25,933
|
|
|
$
|
44,315
|
|
|
$
|
56,336
|
|
|
$
|
121,337
|
|
|
$
|
16,790
|
|
|
$
|
198,793
|
|
|
$
|
170,988
|
|
|
$
|
634,492
|
|
(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
|
|
2014
|
|
2013
|
|
2012
|
||||||
Consolidated Statements of Income
|
|
|
|
|
|
|
||||||
Revenues
|
|
$
|
548,629
|
|
|
$
|
261,705
|
|
|
$
|
199,764
|
|
Operating income
|
|
336,188
|
|
|
171,496
|
|
|
135,498
|
|
|||
Net income
|
|
333,705
|
|
|
170,175
|
|
|
133,987
|
|
|
|
December 31,
|
||||||
thousands
|
|
2014
|
|
2013
|
||||
Consolidated Balance Sheets
|
|
|
|
|
||||
Current assets
|
|
$
|
141,781
|
|
|
$
|
186,690
|
|
Property, plant and equipment, net
|
|
2,814,336
|
|
|
2,676,531
|
|
||
Other assets
|
|
48,799
|
|
|
38,258
|
|
||
Total assets
|
|
$
|
3,004,916
|
|
|
$
|
2,901,479
|
|
Current liabilities
|
|
95,102
|
|
|
206,602
|
|
||
Non-current liabilities
|
|
22,615
|
|
|
34,012
|
|
||
Equity
|
|
2,887,199
|
|
|
2,660,865
|
|
||
Total liabilities and equity
|
|
$
|
3,004,916
|
|
|
$
|
2,901,479
|
|
|
|
December 31,
|
||||||
thousands
|
|
2014
|
|
2013
|
||||
Natural gas liquids inventory
|
|
$
|
5,316
|
|
|
$
|
2,584
|
|
Natural gas imbalance receivables
|
|
415
|
|
|
3,605
|
|
||
Prepaid insurance
|
|
2,443
|
|
|
2,123
|
|
||
Other
|
|
1,893
|
|
|
1,710
|
|
||
Total other current assets
|
|
$
|
10,067
|
|
|
$
|
10,022
|
|
|
|
December 31,
|
||||||
thousands
|
|
2014
|
|
2013
|
||||
Accrued capital expenditures
|
|
$
|
116,891
|
|
|
$
|
94,750
|
|
Accrued plant purchases
|
|
14,023
|
|
|
21,396
|
|
||
Accrued interest expense
|
|
24,741
|
|
|
18,119
|
|
||
Short-term asset retirement obligations
|
|
1,212
|
|
|
1,966
|
|
||
Short-term remediation and reclamation obligations
|
|
475
|
|
|
562
|
|
||
Income taxes payable
|
|
207
|
|
|
—
|
|
||
Other
|
|
1,106
|
|
|
218
|
|
||
Total accrued liabilities
|
|
$
|
158,655
|
|
|
$
|
137,011
|
|
|
|
Year Ended December 31,
|
||||||
thousands
|
|
2014
|
|
2013
|
||||
Carrying amount of asset retirement obligations at beginning of year
|
|
$
|
78,035
|
|
|
$
|
66,723
|
|
Liabilities incurred
|
|
13,769
|
|
|
14,143
|
|
||
Liabilities settled
|
|
(4,181
|
)
|
|
(1,943
|
)
|
||
Accretion expense
|
|
4,846
|
|
|
4,326
|
|
||
Revisions in estimated liabilities
|
|
16,623
|
|
|
(5,214
|
)
|
||
Carrying amount of asset retirement obligations at end of year
|
|
$
|
109,092
|
|
|
$
|
78,035
|
|
|
|
December 31, 2014
|
|
December 31, 2013
|
||||||||||||||||||||
thousands
|
|
Principal
|
|
Carrying
Value
|
|
Fair
Value
(1)
|
|
Principal
|
|
Carrying
Value
|
|
Fair
Value
(1)
|
||||||||||||
5.375% Senior Notes due 2021
|
|
$
|
500,000
|
|
|
$
|
495,714
|
|
|
$
|
549,530
|
|
|
$
|
500,000
|
|
|
$
|
495,173
|
|
|
$
|
533,615
|
|
4.000% Senior Notes due 2022
|
|
670,000
|
|
|
672,930
|
|
|
681,942
|
|
|
670,000
|
|
|
673,278
|
|
|
641,237
|
|
||||||
Revolving credit facility
|
|
510,000
|
|
|
510,000
|
|
|
510,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
2.600% Senior Notes due 2018
|
|
350,000
|
|
|
350,474
|
|
|
352,162
|
|
|
250,000
|
|
|
249,718
|
|
|
247,988
|
|
||||||
5.450% Senior Notes due 2044
|
|
400,000
|
|
|
393,836
|
|
|
417,619
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total long-term debt
|
|
$
|
2,430,000
|
|
|
$
|
2,422,954
|
|
|
$
|
2,511,253
|
|
|
$
|
1,420,000
|
|
|
$
|
1,418,169
|
|
|
$
|
1,422,840
|
|
(1)
|
Fair value is measured using Level 2 inputs.
|
thousands
|
|
Carrying Value
|
||
Balance at December 31, 2012
|
|
$
|
1,168,278
|
|
Revolving credit facility borrowings
|
|
710,000
|
|
|
Repayments of revolving credit facility
|
|
(710,000
|
)
|
|
Issuance of 2.600% Senior Notes due 2018
|
|
250,000
|
|
|
Other
|
|
(109
|
)
|
|
Balance at December 31, 2013
|
|
$
|
1,418,169
|
|
Revolving credit facility borrowings
|
|
1,160,000
|
|
|
Issuance of 5.450% Senior Notes due 2044
|
|
400,000
|
|
|
Issuance of 2.600% Senior Notes due 2018
|
|
100,000
|
|
|
Repayments of revolving credit facility
|
|
(650,000
|
)
|
|
Other
|
|
(5,215
|
)
|
|
Balance at December 31, 2014
|
|
$
|
2,422,954
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2014
|
|
2013
|
|
2012
|
||||||
Third parties
|
|
|
|
|
|
|
||||||
Interest expense on long-term debt
|
|
$
|
81,495
|
|
|
$
|
59,293
|
|
|
$
|
41,171
|
|
Amortization of debt issuance costs and commitment fees
|
|
5,103
|
|
|
4,449
|
|
|
4,319
|
|
|||
Capitalized interest
|
|
(9,832
|
)
|
|
(11,945
|
)
|
|
(6,196
|
)
|
|||
Total interest expense – third parties
|
|
76,766
|
|
|
51,797
|
|
|
39,294
|
|
|||
Affiliates
|
|
|
|
|
|
|
||||||
Interest expense on note payable to Anadarko
(1)
|
|
—
|
|
|
—
|
|
|
2,440
|
|
|||
Interest expense on affiliate balances
(2)
|
|
—
|
|
|
—
|
|
|
326
|
|
|||
Total interest expense – affiliates
|
|
—
|
|
|
—
|
|
|
2,766
|
|
|||
Interest expense
|
|
$
|
76,766
|
|
|
$
|
51,797
|
|
|
$
|
42,060
|
|
(1)
|
In June 2012, the note payable to Anadarko was repaid in full. See
Note payable to Anadarko
within this
Note 12
.
|
(2)
|
Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada complex and Lancaster plant. In the fourth quarter of 2012, the Partnership repaid the reimbursement payable to Anadarko associated with the construction of the Brasada complex and Lancaster plant.
|
thousands
|
Operating Leases
|
||
2015
|
$
|
338
|
|
2016
|
303
|
|
|
2017
|
157
|
|
|
2018
|
34
|
|
|
2019
|
—
|
|
|
Thereafter
|
—
|
|
|
Total
|
$
|
832
|
|
thousands except per-unit amounts
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
2014
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
279,457
|
|
|
$
|
329,944
|
|
|
$
|
326,465
|
|
|
$
|
337,897
|
|
Equity income, net
|
9,251
|
|
|
13,008
|
|
|
19,063
|
|
|
16,514
|
|
||||
Operating income
|
100,158
|
|
|
115,133
|
|
|
123,374
|
|
|
112,922
|
|
||||
Net income
|
91,127
|
|
|
98,482
|
|
|
106,540
|
|
|
94,409
|
|
||||
Net income attributable to Western Gas Partners, LP
|
87,435
|
|
|
95,032
|
|
|
102,677
|
|
|
91,389
|
|
||||
Net income per common unit – basic and diluted
(1)
|
0.54
|
|
|
0.57
|
|
|
0.60
|
|
|
0.42
|
|
||||
2013
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
225,766
|
|
|
$
|
251,402
|
|
|
$
|
273,502
|
|
|
$
|
279,093
|
|
Equity income, net
|
3,968
|
|
|
3,456
|
|
|
4,520
|
|
|
11,004
|
|
||||
Operating income
|
64,023
|
|
|
69,859
|
|
|
90,209
|
|
|
96,767
|
|
||||
Net income
|
52,945
|
|
|
61,876
|
|
|
81,882
|
|
|
88,740
|
|
||||
Net income attributable to Western Gas Partners, LP
|
50,714
|
|
|
60,016
|
|
|
78,506
|
|
|
85,391
|
|
||||
Net income per common unit – basic and diluted
(1)
|
0.31
|
|
|
0.41
|
|
|
0.53
|
|
|
0.56
|
|
(1)
|
Represents net income earned on and subsequent to the acquisition of the Partnership assets (as defined in
Note 1—Summary of Significant Accounting Policies
).
|
Name
|
|
Age
|
|
Position with Western Gas Holdings, LLC
|
|
Robert G. Gwin
|
|
51
|
|
|
Chairman of the Board
|
Donald R. Sinclair
|
|
57
|
|
|
President, Chief Executive Officer and Director
|
Benjamin M. Fink
|
|
44
|
|
|
Senior Vice President, Chief Financial Officer and Treasurer
|
Jacqueline A. Dimpel
|
|
48
|
|
|
Senior Vice President (effective February 27, 2014)
|
Philip H. Peacock
|
|
43
|
|
|
Vice President, General Counsel and Corporate Secretary
|
Steven D. Arnold
|
|
54
|
|
|
Director
|
Milton Carroll
|
|
64
|
|
|
Director
|
James R. Crane
|
|
61
|
|
|
Director
|
Charles A. Meloy
|
|
54
|
|
|
Director
|
Robert K. Reeves
|
|
57
|
|
|
Director
|
David J. Tudor
|
|
55
|
|
|
Director
|
Robert G. Gwin
Age: 51
Houston, Texas
Director since:
August 2007
Not Independent
Officer From:
August 2007 to
January 2010
|
Biography/Qualifications
Robert G. Gwin has served as a director of our general partner since August 2007 and has served as non-executive Chairman of the Board of our general partner since October 2009. He also served as Chief Executive Officer of our general partner from August 2007 to January 2010 and as President from August 2007 to September 2009. Mr. Gwin has served as Chairman of the Board of WGP GP since September 2012. He was named Executive Vice President, Finance and Chief Financial Officer of Anadarko in May 2013 and previously served as Senior Vice President, Finance and Chief Financial Officer beginning in March 2009, prior to which he served as Senior Vice President of Anadarko beginning in March 2008, and as Vice President, Finance and Treasurer beginning in January 2006. Mr. Gwin is Chairman of the Board of LyondellBasell Industries N.V. and he also serves on the boards of The Greater Houston Partnership, Theatre Under the Stars and Communities in Schools. Mr. Gwin holds a Bachelor of Science degree from the University of Southern California and a Master of Business Administration degree from the Fuqua School of Business at Duke University, and he is a Chartered Financial Analyst.
|
|
|
Donald R. Sinclair
Age: 57
Houston, Texas
Director since:
October 2009
Not Independent
Officer Since:
October 2009
|
Biography/Qualifications
Donald R. Sinclair has served as President and a director of our general partner since October 2009 and as Chief Executive Officer since January 2010. Mr. Sinclair has served as the President and Chief Executive Officer and as a director of WGP GP since September 2012. He was named a Senior Vice President of Anadarko in May 2013, prior to which he served as a Vice President of Anadarko beginning in January 2010. Prior to joining Anadarko and becoming President and a director of our general partner, Mr. Sinclair was a founding partner and served as President of Ceritas Energy, LLC, a midstream energy company headquartered in Houston with operations in Texas, Wyoming and Utah from February 2003 to September 2009. Mr. Sinclair has worked in the oil and gas industry for over 33 years, with a focus on marketing and trading and the midstream sector. He is the Vice-Chairman of the Advisory Council for the Rawls College of Business at Texas Tech University. He earned a Bachelor of Business Administration in Management from Texas Tech University.
|
|
|
Benjamin M. Fink
Age: 44
Houston, Texas
Officer since:
May 2009
|
Biography/Qualifications
Benjamin M. Fink has served as the Senior Vice President and Chief Financial Officer of our general partner since May 2009, and as Senior Vice President, Chief Financial Officer and Treasurer of our general partner since November 2010. Mr. Fink has served as Senior Vice President, Chief Financial Officer and Treasurer of WGP GP since September 2012. He was Director, Finance of Anadarko from April 2007 to May 2009, during which time he was responsible for principal oversight of the finance operations of an Anadarko subsidiary, Anadarko Algeria Company, LLC. From August 2006 to April 2007, he served as an independent financial consultant to Anadarko in its Beijing, China and Rio de Janeiro, Brazil offices. From April 2001 until June 2006, he held executive management positions at Prosoft Learning Corporation, including serving as its President and Chief Executive Officer from November 2004 until that company’s sale in June 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. He holds a Bachelor of Science degree in Economics from the Wharton School of the University of Pennsylvania, and he is a Chartered Financial Analyst.
|
James R. Crane
Age: 61
Houston, Texas
Director since:
April 2008
Independent
|
Biography/Qualifications
James R. Crane has served as a director of our general partner and as a member of the Special Committee and Audit Committee of the Board of Directors of our general partner since April 2008. In November 2011, Mr. Crane became the principal owner and Chairman of the Houston Astros Baseball Club. Mr. Crane is also the Chairman and Chief Executive Officer of Crane Capital Group Inc., an investment management company he founded. Crane Capital Group currently invests in transportation, power distribution, real estate and asset management. Its holdings include Crane Worldwide Logistics, a premier global provider of customized transportation and logistics services with 54 offices in 20 countries, and Champion Energy Services, a retail electric provider. Prior to founding Crane Capital Group Inc., he was founder, Chairman and Chief Executive Officer of EGL, Inc., a global transportation, supply chain management and information services company, from 1984 until its sale in August 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 November 2007 he served as a director of HCC Insurance Holdings, Inc. Mr. Crane holds a Bachelor of Science degree in Industrial Safety from the University of Central Missouri.
|
|
|
Charles A. Meloy
Age: 54
Houston, Texas
Director since:
February 2009
Not Independent
|
Biography/Qualifications
Charles A. Meloy has served as a director of our general partner since February 2009 and as a director of WGP GP since September 2012. Mr. Meloy was named Executive Vice President, U.S. Onshore Exploration and Production of Anadarko in May 2013, and previously served as Senior Vice President, U.S. Onshore Exploration and Production beginning in July 2012, prior to which he served as Senior Vice President, Worldwide Operations beginning in December 2006. Before joining Anadarko, he served as Vice President of Exploration and Production at Kerr-McGee Corporation, prior to its acquisition by Anadarko. At Kerr-McGee, Mr. Meloy was Vice President of Gulf of Mexico exploration, production and development from 2004 to 2005, was Vice President and Managing Director of North Sea operations from 2002 to 2004, and held several other deepwater Gulf of Mexico management positions beginning in 1999. Earlier in his career, Mr. Meloy held various planning, operations, deepwater and reservoir engineering positions with Oryx Energy Company and its predecessor, Sun Oil Company. He earned a Bachelor’s degree in Chemical Engineering from Texas A&M University and is a member of the Society of Petroleum Engineers and Texas Professional Engineers. Mr. Meloy is also a member of the Board of Directors of the Independent Producers of America Association.
|
|
|
Robert K. Reeves
Age: 57
Houston, Texas
Director since:
August 2007
Not Independent
|
Biography/Qualifications
Robert K. Reeves has served as a director of our general partner since August 2007 and as a director of WGP GP since September 2012. Mr. Reeves was named Executive Vice President, General Counsel and Chief Administrative Officer of Anadarko in May 2013 and previously served as Senior Vice President, General Counsel and Chief Administrative Officer beginning in February 2007, prior to which he served as Senior Vice President, Corporate Affairs & Law and Chief Governance Officer of Anadarko beginning in 2004. He has also served as a director of Key Energy Services, Inc., a publicly traded oil field services company, since October 2007. Prior to joining Anadarko, he served as Executive Vice President, Administration and General Counsel of North Sea New Ventures from 2003 to 2004 and as Executive Vice President, General Counsel and Secretary of Ocean Energy, Inc. and its predecessor companies from 1997 to 2003. Mr. Reeves holds a Bachelor of Science degree in Business Administration and a Juris Doctor degree from Louisiana State University.
|
David J. Tudor
Age: 55
Houston, Texas
Director since:
April 2008
Independent
|
Biography/Qualifications
David J. Tudor has served as a director of our general partner and as Chairman of the Audit Committee of the Board of Directors of our general partner since April 2008, and previously served as a member of the Special Committee of the Board of Directors of our general partner from April 2008 to December 2012. Mr. Tudor has served as a director of WGP GP and as Chairman of the Audit Committee of its Board of Directors since December 2012. Since May 2013, Mr. Tudor has served as President and Chief Executive Officer of Champion Energy Services, a retail electric provider serving residential, governmental, commercial and industrial customers in a growing number of deregulated electric energy markets throughout the United States. From 1999 through May 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. Mr. Tudor holds a Bachelor of Science degree in Accounting from David Lipscomb University.
|
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
|
|
2014
|
|
304,327
|
|
|
—
|
|
|
807,851
|
|
|
436,272
|
|
|
292,154
|
|
|
77,370
|
|
|
1,917,974
|
|
President and
|
|
2013
|
|
283,414
|
|
|
—
|
|
|
843,813
|
|
|
280,588
|
|
|
243,736
|
|
|
123,110
|
|
|
1,774,661
|
|
Chief Executive Officer
|
2012
|
|
271,298
|
|
|
—
|
|
|
506,296
|
|
|
168,623
|
|
|
—
|
|
|
113,250
|
|
|
1,059,467
|
|
|
Benjamin M. Fink
|
|
2014
|
|
300,635
|
|
|
—
|
|
|
646,283
|
|
|
349,017
|
|
|
234,495
|
|
|
76,436
|
|
|
1,606,866
|
|
Senior Vice President, Chief
|
|
2013
|
|
280,904
|
|
|
—
|
|
|
760,623
|
|
|
202,020
|
|
|
191,015
|
|
|
121,704
|
|
|
1,556,266
|
|
Financial Officer and Treasurer
|
2012
|
|
263,062
|
|
|
—
|
|
|
261,073
|
|
|
—
|
|
|
—
|
|
|
109,813
|
|
|
633,948
|
|
|
Jacqueline A. Dimpel
|
|
2014
|
|
82,260
|
|
|
—
|
|
|
273,490
|
|
|
139,580
|
|
|
64,163
|
|
|
20,945
|
|
|
580,438
|
|
Senior Vice President
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Philip H. Peacock
|
|
2014
|
|
128,510
|
|
|
—
|
|
|
87,515
|
|
|
—
|
|
|
61,685
|
|
|
30,766
|
|
|
308,476
|
|
Vice President, General Counsel
|
|
2013
|
|
121,154
|
|
|
—
|
|
|
70,016
|
|
|
—
|
|
|
58,154
|
|
|
52,482
|
|
|
301,806
|
|
and Corporate Secretary
|
|
2012
|
|
43,269
|
|
|
—
|
|
|
75,006
|
|
|
—
|
|
|
18,173
|
|
|
17,960
|
|
|
154,408
|
|
(1)
|
The amounts in this column reflect the base salary compensation allocated to us by Anadarko for the years ended
December 31, 2014
,
2013
and
2012
.
|
(2)
|
The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for non-option stock awards granted pursuant to the WES LTIP, the WGP LTIP and the 2008 and 2012 Anadarko Omnibus Incentive Compensation Plans and include unvested amounts. For awards of phantom units granted under the WES LTIP and WGP LTIP, the grant date value is determined by multiplying the number of phantom units awarded by the per-unit closing price of the underlying common units on the date of grant. For a discussion of valuation assumptions for the awards under the 2008 and 2012 Anadarko Omnibus Incentive Compensation Plans, see
Note 15—Share-Based Compensation
in the
Notes to Consolidated Financial Statements
included under Item 8 of Anadarko’s Form 10-K for the year ended
December 31, 2014
(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
2014
, please see the Grants of Plan-Based Awards Table.
|
(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 2008 and 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
2014
, please 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, 2014
, and allocated to us for the years ended December 31,
2013
and
2012
. The
2014
amounts represent payments which were earned in
2014
and are expected to be paid in early
2015
, the
2013
amounts represent payments which were earned in
2013
and paid in early
2014
and the
2012
amounts represent the payments which were earned in
2012
and paid in early
2013
. For an explanation of the
2014
annual incentive plan awards, please read
Compensation Discussion and Analysis – Analysis of
2014
Compensation Actions – Performance-Based Annual Cash Incentives (Bonuses),
contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
April 2, 2015
.
|
(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, 2014
,
2013
and
2012
. The
2014
allocated expenses are detailed in the table below:
|
Name
|
|
Retirement Plan Expense
|
|
Savings Plan
Expense
|
||||
Donald R. Sinclair
|
|
$
|
49,515
|
|
|
$
|
27,855
|
|
Benjamin M. Fink
|
|
48,918
|
|
|
27,518
|
|
||
Jacqueline A. Dimpel
|
|
13,402
|
|
|
7,543
|
|
||
Philip H. Peacock
|
|
19,757
|
|
|
11,009
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
243,462
|
|
|
292,154
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
11/06/14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,309
|
|
|
|
|
|
|
309,425
|
|
||||||||
11/06/14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18,520
|
|
|
93.51
|
|
|
436,272
|
|
|||||||
11/06/14
|
|
|
|
|
|
|
|
1,995
|
|
|
4,987
|
|
|
9,974
|
|
|
|
|
|
|
|
|
498,426
|
|
||||||
Benjamin M. Fink
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
195,413
|
|
|
234,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
11/06/14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,647
|
|
|
|
|
|
|
247,512
|
|
||||||||
11/06/14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,816
|
|
|
93.51
|
|
|
349,017
|
|
|||||||
11/06/14
|
|
|
|
|
|
|
|
1,596
|
|
|
3,990
|
|
|
7,980
|
|
|
|
|
|
|
|
|
398,771
|
|
||||||
Jacqueline A. Dimpel
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
53,469
|
|
|
64,163
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
01/08/14
|
|
|
|
|
|
|
|
235
|
|
|
872
|
|
|
1,744
|
|
|
|
|
|
|
|
|
87,856
|
|
||||||
01/08/14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
593
|
|
|
|
|
|
|
46,890
|
|
||||||||
01/08/14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,938
|
|
|
79.04
|
|
|
64,663
|
|
|||||||
11/06/14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
568
|
|
|
|
|
|
|
53,137
|
|
||||||||
11/06/14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,180
|
|
|
93.51
|
|
|
74,917
|
|
|||||||
11/06/14
|
|
|
|
|
|
|
|
343
|
|
|
857
|
|
|
1,714
|
|
|
|
|
|
|
|
|
85,607
|
|
||||||
Philip H. Peacock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
51,404
|
|
|
61,685
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
03/06/14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,012
|
|
|
|
|
|
|
87,515
|
|
(1)
|
Reflects the estimated
2014
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
2014
is reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. For additional discussion of Anadarko’s annual incentive plan please read
Compensation Discussion and Analysis — Analysis of
2014
Compensation Actions — Performance-Based Annual Cash Incentives (Bonuses)
contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
April 2, 2015
.
|
(2)
|
Reflects the estimated future payout allocable to us under Anadarko’s performance units awarded in
2014
. 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. With respect to the performance units granted to Ms. Dimpel on January 8, 2014, fifty percent of this award is tied to a two-year performance period and the remaining fifty percent is tied to a three-year performance period. The performance units granted to Messrs. Sinclair and Fink and Ms. Dimpel on November 6, 2014 are subject solely 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 please read
Compensation Discussion and Analysis — Analysis of
2014
Compensation Actions — Equity Compensation
contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
April 2, 2015
.
|
(3)
|
Reflects the allocable number of restricted stock shares and restricted stock units awarded in 2014 under the Omnibus Plan. These awards vest equally over three years, beginning with the first anniversary of the grant date. Executive officers receive dividends on the restricted stock shares. For restricted stock units, dividend equivalents are reinvested in shares of Anadarko common stock and paid upon the applicable vesting of the underlying award.
|
(4)
|
Reflects the allocable number of Anadarko stock options each named executive officer was awarded in
2014
. 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
2014
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 15—Share-Based Compensation
in the
Notes to Consolidated Financial Statements
under Item 8 of Anadarko’s Form 10-K for the year ended
December 31, 2014
(which is not, and shall not be deemed to be, incorporated by reference herein).
|
(1)
|
The table below shows the vesting dates for the respective unexercisable stock options listed in the above Outstanding Equity Awards Table:
|
Vesting Date
|
|
Donald R. Sinclair
|
|
Benjamin M. Fink
|
|
Jacqueline A. Dimpel
|
|
Philip H. Peacock
|
||||
01/08/2015
|
|
—
|
|
|
—
|
|
|
980
|
|
|
—
|
|
06/07/2015
|
|
—
|
|
|
484
|
|
|
—
|
|
|
—
|
|
11/05/2015
|
|
2,169
|
|
|
—
|
|
|
—
|
|
|
—
|
|
11/06/2015
|
|
3,606
|
|
|
2,019
|
|
|
1,060
|
|
|
—
|
|
11/06/2015
|
|
6,173
|
|
|
4,939
|
|
|
—
|
|
|
—
|
|
01/08/2016
|
|
—
|
|
|
—
|
|
|
980
|
|
|
—
|
|
06/07/2016
|
|
—
|
|
|
484
|
|
|
—
|
|
|
—
|
|
11/06/2016
|
|
3,606
|
|
|
2,019
|
|
|
1,060
|
|
|
—
|
|
11/06/2016
|
|
6,173
|
|
|
4,939
|
|
|
—
|
|
|
—
|
|
01/08/2017
|
|
—
|
|
|
—
|
|
|
979
|
|
|
—
|
|
11/06/2017
|
|
6,173
|
|
|
4,938
|
|
|
1,060
|
|
|
—
|
|
(2)
|
The table below shows the vesting dates for the respective phantom units, restricted stock shares and restricted stock units listed in the above Outstanding Equity Awards Table:
|
Vesting Date
|
|
Donald R. Sinclair
|
|
Benjamin M. Fink
|
|
Jacqueline A. Dimpel
|
|
Philip H. Peacock
|
||||
01/08/2015
|
|
—
|
|
|
—
|
|
|
200
|
|
|
—
|
|
03/03/2015
|
|
—
|
|
|
1,054
|
|
|
147
|
|
|
—
|
|
03/06/2015
|
|
—
|
|
|
—
|
|
|
—
|
|
|
338
|
|
03/07/2015
|
|
—
|
|
|
978
|
|
|
161
|
|
|
282
|
|
06/07/2015
|
|
—
|
|
|
173
|
|
|
—
|
|
|
—
|
|
09/04/2015
|
|
—
|
|
|
—
|
|
|
—
|
|
|
362
|
|
11/05/2015
|
|
811
|
|
|
—
|
|
|
—
|
|
|
—
|
|
11/06/2015
|
|
1,032
|
|
|
578
|
|
|
190
|
|
|
—
|
|
11/06/2015
|
|
1,106
|
|
|
886
|
|
|
—
|
|
|
—
|
|
11/14/2015
|
|
2,394
|
|
|
—
|
|
|
—
|
|
|
—
|
|
11/20/2015
|
|
4,561
|
|
|
2,554
|
|
|
—
|
|
|
—
|
|
01/08/2016
|
|
—
|
|
|
—
|
|
|
200
|
|
|
—
|
|
03/06/2016
|
|
—
|
|
|
—
|
|
|
—
|
|
|
337
|
|
03/07/2016
|
|
—
|
|
|
978
|
|
|
161
|
|
|
282
|
|
06/07/2016
|
|
—
|
|
|
174
|
|
|
—
|
|
|
—
|
|
11/06/2016
|
|
1,032
|
|
|
578
|
|
|
190
|
|
|
—
|
|
11/06/2016
|
|
1,106
|
|
|
885
|
|
|
—
|
|
|
—
|
|
11/20/2016
|
|
4,561
|
|
|
2,554
|
|
|
—
|
|
|
—
|
|
01/08/2017
|
|
—
|
|
|
—
|
|
|
200
|
|
|
—
|
|
03/06/2017
|
|
—
|
|
|
—
|
|
|
—
|
|
|
337
|
|
11/06/2017
|
|
1,106
|
|
|
885
|
|
|
190
|
|
|
—
|
|
(3)
|
The table below shows the performance periods for the respective performance units listed in the above Outstanding Equity Awards Table. Generally, the number of outstanding units for each award is calculated based on Anadarko’s relative performance ranking as of
December 31, 2014
, and is not necessarily indicative of what the payout percent earned will be at the end of the performance period. As of
December 31, 2014
, the performance to date calculation for the awards with performance periods beginning January 1,
2014
was 146%. For awards with performance periods beginning January 1,
2015
, target payout has been assumed.
|
Performance Period
|
|
APC Performance
to Date Payout % |
|
Donald R. Sinclair
Performance
Units
|
|
Benjamin M. Fink
Performance
Units
|
|
Jacqueline A. Dimpel
Performance
Units
|
1/1/2014 to 12/31/2015
|
|
146%
|
|
—
|
|
—
|
|
636
|
1/1/2014 to 12/31/2016
|
|
146%
|
|
—
|
|
—
|
|
636
|
1/1/2015 to 12/31/2017
|
|
100%
|
|
4,987
|
|
3,990
|
|
857
|
(4)
|
These awards represent grants of phantom units under the WES LTIP. The market values for these awards are based on the closing common unit price for the Partnership on
December 31, 2014
, of
$73.05
.
|
(5)
|
These awards represent grants of phantom units under the WGP LTIP. The market values for these awards are based on the closing common unit price for WGP on
December 31, 2014
of
$60.23
.
|
|
|
Option Awards
|
|
Stock Awards
|
||||||||
Name
|
|
Number of Shares Acquired on Exercise (#)
(1)
|
|
Value Realized on Exercise ($)
(1)
|
|
Number of Shares Acquired on Vesting (#)
(2)
|
|
Value Realized on Vesting ($)
(2)
|
||||
Donald R. Sinclair
|
|
—
|
|
|
—
|
|
|
8,281
|
|
|
636,053
|
|
Benjamin M. Fink
|
|
—
|
|
|
—
|
|
|
3,440
|
|
|
300,565
|
|
Jacqueline A. Dimpel
|
|
—
|
|
|
—
|
|
|
424
|
|
|
36,136
|
|
Philip H. Peacock
|
|
—
|
|
|
—
|
|
|
644
|
|
|
63,270
|
|
(1)
|
Shares acquired and values realized on exercise include options exercised in
2014
. 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
2014
of restricted stock shares or units, performance units, or phantom units. For restricted stock shares or units and phantom units, the actual value ultimately realized by the named executive officer may be more or less than the value realized calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise or vesting occurrence.
|
Name
|
|
Accelerated WES/WGP LTIP Awards
(1)
|
||
Donald R. Sinclair
|
|
$
|
724,270
|
|
Benjamin M. Fink
|
|
307,679
|
|
|
Jacqueline A. Dimpel
|
|
—
|
|
|
Philip H. Peacock
|
|
—
|
|
(1)
|
WES LTIP phantom units are valued based on the closing WES common unit price of
$73.05
on
December 31, 2014
; WGP LTIP phantom units are valued based on the closing WGP common unit price of
$60.23
on
December 31, 2014
.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Cash Severance
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Cash Severance
(1)
|
$
|
945,000
|
|
|
$
|
870,525
|
|
|
$
|
238,500
|
|
|
$
|
—
|
|
Pro-rata Bonus for 2014
(2)
|
292,154
|
|
|
234,495
|
|
|
64,163
|
|
|
—
|
|
||||
Accelerated Anadarko Equity Compensation
(3)
|
948,018
|
|
|
920,477
|
|
|
320,916
|
|
|
159,761
|
|
||||
Health and Welfare Benefits
(4)
|
67,040
|
|
|
46,004
|
|
|
9,796
|
|
|
—
|
|
||||
Total
|
$
|
2,252,212
|
|
|
$
|
2,071,501
|
|
|
$
|
633,375
|
|
|
$
|
159,761
|
|
(1)
|
Messrs. Sinclair’s and Fink’s and Ms. Dimpel’s values assume two times base salary plus one times target bonus multiplied by their allocation percentages in effect as of
December 31, 2014
. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(2)
|
Payment, if provided, will be paid at the end of the performance period based on actual performance. The values for Messrs. Sinclair and Fink and Ms. Dimpel reflect the allocated portion of their actual bonuses awarded under the AIP. For additional discussion of this program please read
Compensation Discussion and Analysis — Analysis of
2014
Compensation Actions — Performance-Based Annual Cash Incentives (Bonuses)
of Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
April 2, 2015
. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(3)
|
Reflects the in-the-money value of unvested stock options, the estimated current value of unvested performance units (based on performance to date) and the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of
December 31, 2014
. In the event of an involuntary termination, unvested performance units would be paid after the end of the applicable performance period, based on actual performance. All values reflect each named executive officer’s allocation percentage in effect as of
December 31, 2014
.
|
(4)
|
Messrs. Sinclair’s and Fink’s and Ms. Dimpel’s values represent 24 months of health and welfare benefit coverage. These amounts are present values determined in accordance with the generally accepted accounting principles in the United States (“GAAP”). These values reflect their allocation percentage in effect as of
December 31, 2014
. 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)
|
$
|
2,011,875
|
|
|
$
|
1,220,400
|
|
|
$
|
280,000
|
|
|
$
|
—
|
|
Pro-rata Bonus for 2014
(2)
|
356,250
|
|
|
281,700
|
|
|
50,000
|
|
|
—
|
|
||||
Accelerated Anadarko Equity Compensation
(3)
|
948,018
|
|
|
920,477
|
|
|
320,916
|
|
|
159,761
|
|
||||
Accelerated WES/WGP Equity Compensation
(4)
|
724,270
|
|
|
307,679
|
|
|
—
|
|
|
—
|
|
||||
Supplemental Pension Benefits
(5)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Nonqualified Deferred Compensation
(6)
|
208,125
|
|
|
122,040
|
|
|
16,800
|
|
|
—
|
|
||||
Health and Welfare Benefits
(7)
|
101,144
|
|
|
46,004
|
|
|
9,796
|
|
|
—
|
|
||||
Total
|
$
|
4,349,682
|
|
|
$
|
2,898,300
|
|
|
$
|
677,512
|
|
|
$
|
159,761
|
|
(1)
|
Mr. Sinclair’s values and Mr. Fink’s and Ms. Dimpel’s values assume 2.9 times and two times, respectively, the sum of base salary plus the highest bonus paid in the past three years and reflect their allocation percentages in effect as of
December 31, 2014
, per the terms of their key employee change of control agreements with Anadarko. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(2)
|
Messrs. Sinclair’s and Fink’s and Ms. Dimpel’s values assume the full-year equivalent of their highest annual bonus allocated to us over the past three years. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(3)
|
Reflects the in-the-money value of unvested stock options, the value of unvested restricted stock shares and restricted stock units and the estimated current value of unvested performance units (based on performance to date) granted under Anadarko equity plans, all as of
December 31, 2014
. 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, 2014
.
|
(4)
|
Reflects the value of unvested WES and WGP LTIP phantom units based on the applicable closing common unit price of
$73.05
and
$60.23
, respectively, on
December 31, 2014
. All values reflect each named executive officer’s allocation percentage in effect as of
December 31, 2014
.
|
(5)
|
Under the terms of their change of control agreements, Messrs. Sinclair and Fink and Ms. Dimpel would receive a special retirement benefit enhancement that is equivalent to the additional supplemental pension benefits that would have accrued under Anadarko’s retirement plan assuming they were eligible for subsidized early retirement benefits and include additional special pension credits. The value of this benefit has not been included in this table as Anadarko does not allocate expense to the partnership for distribution of these benefits. If Anadarko were to allocate this expense to the Partnership, assuming their allocation percentages in effect as of
December 31, 2014
, the expense would be as follows: Mr. Sinclair—$185,512, Mr. Fink—$86,295 and Ms. Dimpel—$137,894.
|
(6)
|
Mr. Sinclair’s values and Mr. Fink’s and Ms. Dimpel’s values reflect an additional three years and two years, respectively, of employer contributions into the savings restoration plan at their current contribution rate to the Plan and are based on their allocation percentages in effect as of
December 31, 2014
, per the terms of their key employee change of control agreements with Anadarko. No value has been disclosed for Mr. Peacock as he is not eligible for this additional benefit.
|
(7)
|
Mr. Sinclair’s values and Mr. Fink’s and Ms. Dimpel’s values represent 36 months and 24 months, respectively, of health and welfare benefit coverage. All amounts are present values determined in accordance with GAAP and reflect their allocation percentages in effect as of
December 31, 2014
. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Cash Severance
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accelerated Anadarko Equity Compensation
(1)
|
948,018
|
|
|
920,477
|
|
|
320,916
|
|
|
159,761
|
|
||||
Health and Welfare Benefits
(2)
|
102,649
|
|
|
142,702
|
|
|
24,631
|
|
|
56,406
|
|
||||
Total
|
$
|
1,050,667
|
|
|
$
|
1,063,179
|
|
|
$
|
345,547
|
|
|
$
|
216,167
|
|
(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, 2014
. 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, 2014
.
|
(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, 2014
.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Ms. Dimpel
|
|
Mr. Peacock
|
||||||||
Cash Severance
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accelerated Anadarko Equity Compensation
(1)
|
948,018
|
|
|
920,477
|
|
|
287,842
|
|
|
159,761
|
|
||||
Life Insurance Proceeds
(2)
|
1,609,058
|
|
|
1,566,150
|
|
|
429,082
|
|
|
619,487
|
|
||||
Total
|
$
|
2,557,076
|
|
|
$
|
2,486,627
|
|
|
$
|
716,924
|
|
|
$
|
779,248
|
|
(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, 2014
. All values reflect each named executive officer’s allocation percentage in effect as of
December 31, 2014
.
|
(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, 2014
, 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 22,
2014
.
|
Name
|
|
Fees Earned or Paid in Cash
|
|
Stock Awards
(1)
|
|
Option Awards
|
|
Non-Equity Incentive Plan Compensation
|
|
All Other Compensation
|
|
Total
|
||||||||||||
Steven D. Arnold
|
|
$
|
113,000
|
|
|
$
|
125,029
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
238,029
|
|
Milton Carroll
|
|
123,000
|
|
|
90,069
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
213,069
|
|
||||||
James R. Crane
|
|
115,000
|
|
|
90,069
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
205,069
|
|
||||||
David J. Tudor
|
|
127,000
|
|
|
90,069
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
217,069
|
|
(1)
|
The amounts included in the Stock Awards column represent the grant date fair value of non-option awards made to directors in
2014
, 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 Item 8 of this Form 10-K. As of
December 31, 2014
, each of the non-employee directors had 1,262 outstanding phantom units, except for Mr. Arnold who was granted 2,014 phantom units upon his appointment as director in February 2014.
|
Name
|
|
Grant Date
|
|
Phantom Units (#)
|
|
Grant Date Fair Value of Stock and Option Awards ($)
(1)
|
||
Steven D. Arnold
|
|
February 27
|
|
2,014
|
|
|
125,029
|
|
Milton Carroll
|
|
May 22
|
|
1,262
|
|
|
90,069
|
|
James R. Crane
|
|
May 22
|
|
1,262
|
|
|
90,069
|
|
David J. Tudor
|
|
May 22
|
|
1,262
|
|
|
90,069
|
|
(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
2014
computed in accordance with FASB ASC Topic 718. The value ultimately realized by a director upon the actual vesting of the award(s) may or may not be equal to the determined value.
|
•
|
each member of the Board of Directors of our general partner;
|
•
|
each named executive officer of our general partner;
|
•
|
all directors and officers of our general partner as a group; and
|
•
|
Anadarko and its affiliates.
|
|
|
WES
|
|
WGP
|
||||||
Name and Address of Beneficial Owner
(1)
|
|
Common
Units
Beneficially Owned
|
|
Percentage of
Common Units
Beneficially
Owned
|
|
Common
Units
Beneficially
Owned
|
|
Percentage of
Common Units
Beneficially
Owned
|
||
Anadarko Petroleum Corporation
(2)
|
|
50,053,824
|
|
|
39.20%
|
|
193,387,365
|
|
|
88.35%
|
Robert G. Gwin
|
|
10,000
|
|
|
*
|
|
200,000
|
|
|
*
|
Donald R. Sinclair
(3)
|
|
112,845
|
|
|
*
|
|
303,917
|
|
|
*
|
Benjamin M. Fink
(3)
|
|
2,213
|
|
|
*
|
|
14,561
|
|
|
*
|
Jacqueline A. Dimpel
|
|
—
|
|
|
*
|
|
100
|
|
|
*
|
Philip H. Peacock
|
|
—
|
|
|
*
|
|
7,500
|
|
|
*
|
Steven D. Arnold
(3)
|
|
31,000
|
|
|
*
|
|
7,500
|
|
|
*
|
Milton Carroll
(3) (4)
|
|
4,157
|
|
|
*
|
|
4,000
|
|
|
*
|
James R. Crane
(3) (4)
|
|
503,798
|
|
|
*
|
|
—
|
|
|
*
|
Charles A. Meloy
|
|
3,000
|
|
|
*
|
|
5,000
|
|
|
*
|
Robert K. Reeves
|
|
9,000
|
|
|
*
|
|
9,000
|
|
|
*
|
David J. Tudor
(3)
|
|
10,333
|
|
|
*
|
|
4,574
|
|
|
*
|
All directors and executive officers
as a group (11 persons)
(3) (4)
|
|
686,346
|
|
|
*
|
|
556,152
|
|
|
*
|
*
|
Less than 1%
|
(1)
|
The address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.
|
(2)
|
WGP held
49,296,205
common units and other subsidiaries of Anadarko, Anadarko Marcellus Midstream, L.L.C. (“AMM”) and APC Midstream Holdings, LLC (“AMH”), collectively held
757,619
common units. Anadarko is the ultimate parent company of Western Gas Resources, Inc. (“WGRI”), AMM, AMH and WGP GP and may, therefore, be deemed to beneficially own the units held by such parties. Anadarko, through AMH, also held
10,959,564
Class C units of the Partnership.
|
(3)
|
Does not include (a) 1,262 unvested phantom units that were granted to each of Messrs. Carroll, Crane and Tudor, 2,014 unvested phantom units granted to Mr. Arnold and 3,192 unvested phantom units previously granted to Mr. Sinclair under the WES LTIP, and (b) an aggregate 17,838 unvested phantom units that were previously granted to Messrs. Sinclair and Fink under the WGP LTIP. Phantom units granted to the independent directors of WES vest 100% on the first anniversary of the date of the grant, and Mr. Sinclair’s and Mr. Fink’s phantom unit awards vest pro-rata over three years. Each vested phantom unit entitles the holder to receive a common unit or, in the discretion of our general partner’s Board of Directors, cash equal to the fair market value of a common unit. Holders of phantom units are entitled to distribution equivalents on a current basis. Holders of phantom units have no voting rights until such time as the phantom units become vested and common units are issued to such holders.
|
(4)
|
Includes (a) 2,000 and 495,601 WES units held by Messrs. Carroll and Crane, respectively, and (b) 4,000 WGP units held by Mr. Carroll, in margin accounts.
|
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)
|
|
70,563
|
|
|
358,494
|
|
|
429,057
|
|
|
*
|
Donald R. Sinclair
(3)
|
|
14,406
|
|
|
26,334
|
|
|
40,740
|
|
|
*
|
Benjamin M. Fink
(3)
(4)
|
|
9,470
|
|
|
15,002
|
|
|
24,472
|
|
|
*
|
Jacqueline A. Dimpel
(3) (4)
|
|
8,835
|
|
|
5,029
|
|
|
13,864
|
|
|
*
|
Philip H. Peacock
(4)
|
|
4,136
|
|
|
—
|
|
|
4,136
|
|
|
*
|
Steven D. Arnold
|
|
13,600
|
|
|
—
|
|
|
13,600
|
|
|
*
|
Milton Carroll
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
James R. Crane
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Charles A. Meloy
(3)
|
|
106,250
|
|
|
196,233
|
|
|
302,483
|
|
|
*
|
Robert K. Reeves
(3)
|
|
166,034
|
|
|
282,324
|
|
|
448,358
|
|
|
*
|
David J. Tudor
|
|
—
|
|
|
—
|
|
|
—
|
|
|
*
|
All directors and executive officers
as a group (11 persons)
(3) (4)
|
|
393,294
|
|
|
883,416
|
|
|
1,276,710
|
|
|
*
|
*
|
Less than 1%
|
(1)
|
The address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.
|
(2)
|
As of January 31,
2015
, there were 506.7 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—26,393; Donald R. Sinclair—8,232; Benjamin M. Fink—4,605; Jacqueline A. Dimpel—4,663; Charles A. Meloy—27,018; Robert K. Reeves—20,660; and a total of 91,571 unvested restricted stock units are held by the directors and executive officers as a group. Restricted stock units typically vest equally over three years beginning on the first anniversary of the date of grant, and upon vesting are payable in Anadarko common stock, subject to applicable tax withholding. Holders of restricted stock units receive dividend equivalents on the units, but do not have voting rights. Generally, a holder will forfeit any unvested restricted units if he or she terminates voluntarily or is terminated for cause prior to the vesting date. Holders of restricted stock units have the ability to defer such awards.
|
(4)
|
Includes unvested shares of restricted common stock of Anadarko held by the following individuals in the amounts indicated: Benjamin M. Fink—3,345; Jacqueline A. Dimpel—1,874; Philip H. Peacock—3,873; and a total of 9,092 unvested shares of restricted common stock are held by the directors and executive officers as a group. Restricted stock awards typically vest equally over three years beginning on the first anniversary of the date of grant. Holders of restricted stock receive dividends on the shares and also have voting rights. Generally, a holder of restricted stock will forfeit any unvested restricted shares if he or she terminates voluntarily or is terminated for cause prior to the vesting date.
|
Title of Class
|
|
Name and Address of Beneficial Owner
|
|
Amount and
Nature
of Beneficial
Ownership
|
|
Percent of Class
|
Common Units
|
|
Neuberger Berman Group LLC
605 Third Avenue
New York, NY 10158
|
|
6,683,147
(1)
|
|
5.30%
|
Common Units
|
|
Tortoise Capital Advisors, L.L.C.
11550 Ash Street
Suite 300
Leawood, KS 66211
|
|
8,257,605
(2)
|
|
6.50%
|
Common Units
|
|
Kayne Anderson Capital Advisors, L.P.
1800 Avenue of the Stars Third Floor Los Angeles, CA 90067 |
|
8,019,103
(3)
|
|
6.70%
|
(1)
|
Based upon its Schedule 13G filed February 12,
2015
, with the SEC with respect to Partnership securities held as of
December 31, 2014
, Neuberger Berman Group LLC has shared voting power as to 6,437,942 common units and shared dispositive power as to 6,683,147 common units.
|
(2)
|
Based upon its Schedule 13G/A filed February 10,
2015
, with the SEC with respect to Partnership securities held as of
December 31, 2014
, Tortoise Capital Advisors, L.L.C. has shared voting power as to 7,685,801 common units and shared dispositive power as to 8,257,574 common units.
|
(3)
|
Based upon its Schedule 13G/A filed January 14,
2015
, with the SEC with respect to Partnership securities held as of
December 31, 2014
, Kayne Anderson Capital Advisors, L.P. has shared voting and dispositive power as to 8,019,103 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)
|
|
9,522
|
|
|
—
(2)
|
|
|
2,133,227
|
|
Total
|
|
9,522
|
|
|
—
|
|
|
2,133,227
|
|
(1)
|
The Board of Directors of our general partner adopted the WES LTIP in connection with the initial public offering of our common units.
|
(2)
|
Phantom units constitute the only rights outstanding under the WES LTIP. Each phantom unit that may be settled in common units entitles the holder to receive, upon vesting, one common unit with respect to each phantom unit, without payment of any cash. Accordingly, there is no reportable weighted-average exercise price.
|
Formation stage
|
|
|
|
|
|
The consideration received by Anadarko for the contribution of the assets and liabilities to us
|
|
5,725,431 common units; 26,536,306 subordinated units; 1,083,115 general partner units, and our IDRs.
|
|
|
|
Operational stage
|
|
|
|
|
|
Distributions of available cash to our general partner, WGP and other subsidiaries of Anadarko
|
|
We will generally make cash distributions of 98.1% to our unitholders pro rata, including WGP and other subsidiaries of Anadarko as the holders of 49,296,205 common units and 757,619 common units, respectively, and 1.9% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50.1% of the distributions above the highest target distribution level.
As of December 31, 2014, the general partner was entitled to a maximum distribution sharing percentage of 49.9%, which includes distributions paid on its 1.9% 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 Item 8 of this Form 10-K.
|
|
|
|
Distributions of additional Class C units
|
|
In connection with the closing of the Delaware Basin Midstream, LLC (“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. 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
2014
); 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, 2014 |
||
Reimbursement of general and administrative expenses
|
|
$
|
20,249
|
|
Reimbursement of public company expenses
|
|
8,006
|
|
|
Total reimbursement
|
|
$
|
28,255
|
|
•
|
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,
|
||||||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|
2014
|
|
2013
|
|
2012
|
||||||||||||
thousands
|
|
Purchases
|
|
Sales
|
||||||||||||||||||||
Cash consideration
|
|
$
|
22,943
|
|
|
$
|
11,211
|
|
|
$
|
24,705
|
|
|
$
|
—
|
|
|
$
|
85
|
|
|
$
|
760
|
|
Net carrying value
|
|
12,210
|
|
|
5,309
|
|
|
8,009
|
|
|
—
|
|
|
38
|
|
|
393
|
|
||||||
Partners’ capital adjustment
|
|
$
|
10,733
|
|
|
$
|
5,902
|
|
|
$
|
16,696
|
|
|
$
|
—
|
|
|
$
|
47
|
|
|
$
|
367
|
|
|
|
Year ended December 31,
|
||||||||||
thousands
|
|
2014
|
|
2013
|
|
2012
|
||||||
Revenues
(1)
|
|
$
|
969,995
|
|
|
$
|
805,526
|
|
|
$
|
688,026
|
|
Equity income, net
(1)
|
|
57,836
|
|
|
22,948
|
|
|
16,042
|
|
|||
Cost of product
(1)
|
|
114,000
|
|
|
129,045
|
|
|
145,250
|
|
|||
Operation and maintenance
(2)
|
|
58,884
|
|
|
56,435
|
|
|
51,237
|
|
|||
General and administrative
(3)
|
|
26,989
|
|
|
23,354
|
|
|
92,847
|
|
|||
Operating expenses
|
|
199,873
|
|
|
208,834
|
|
|
289,334
|
|
|||
Interest income
(4)
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
(5)
|
|
—
|
|
|
—
|
|
|
2,766
|
|
|||
Distributions to unitholders
(6)
|
|
234,024
|
|
|
169,150
|
|
|
98,280
|
|
|||
Contributions from noncontrolling interest owners
(7)
|
|
—
|
|
|
—
|
|
|
12,588
|
|
|||
Distributions to noncontrolling interest owners
(7)
|
|
—
|
|
|
—
|
|
|
6,528
|
|
(1)
|
Represents amounts earned or incurred on and subsequent to the date of acquisition of our assets, as well as amounts earned or incurred by Anadarko on a historical basis related to our assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.
|
(2)
|
Represents expenses incurred on and subsequent to the date of the acquisition of our assets, as well as expenses incurred by Anadarko on a historical basis related to our assets prior to the acquisition of such assets.
|
(3)
|
Represents general and administrative expense incurred on and subsequent to the date of the acquisition of our assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of our assets by us. These amounts include equity-based compensation expense allocated to us by Anadarko. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(4)
|
Represents interest income recognized on the note receivable from Anadarko.
|
(5)
|
For the year ended December 31, 2012, includes interest expense recognized on the note payable to Anadarko (see
Note 12—Debt and Interest Expense
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada complex and Lancaster plant. We repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko associated with the construction of the Brasada complex and Lancaster plant in the fourth quarter of 2012.
|
(6)
|
Represents distributions paid under the partnership agreement. See
Note 3—Partnership Distributions
and
Note 4—Equity and Partners’ Capital
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(7)
|
We acquired Anadarko’s then-remaining interest in Chipeta on August 1, 2012 (see
Note 2—Acquisitions
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K), and accounted for the acquisition on a prospective basis. As such, contributions from noncontrolling interest owners and distributions to noncontrolling interest owners subsequent to the acquisition date no longer reflect contributions from or distributions to Anadarko.
|
•
|
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
|
|
2014
|
|
2013
|
||||
Audit fees
|
|
$
|
1,227
|
|
|
$
|
1,031
|
|
Audit-related fees
|
|
491
|
|
|
758
|
|
||
Total
|
|
$
|
1,718
|
|
|
$
|
1,789
|
|
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).
|
Exhibit
Number
|
|
Description
|
2.7#
|
|
Contribution Agreement, dated as of December 15, 2011, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 15, 2011, File No. 001-34046).
|
2.8#
|
|
Contribution Agreement, dated as of February 27, 2013, by and among Anadarko Marcellus Midstream, L.L.C., Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP, Anadarko Petroleum Corporation and Anadarko E&P Onshore LLC (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
|
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 the Annual Report on Form 10-K filed by Western Gas Partners, LP 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).
|
3.1
|
|
Certificate of Limited Partnership of Western Gas Partners, LP (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
|
3.2
|
|
First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated May 14, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
3.3
|
|
Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated December 19, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 24, 2008, File No. 001-34046).
|
3.4
|
|
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated as of April 15, 2009 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on April 20, 2009, File No. 001-34046).
|
3.5
|
|
Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated July 22, 2009 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
|
3.6
|
|
Amendment No. 4 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated January 29, 2010 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010, File No. 001-34046).
|
3.7
|
|
Amendment No. 5 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated August 2, 2010 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046).
|
3.8
|
|
Amendment No. 6 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated July 8, 2011 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 8, 2011, File No. 001-34046).
|
3.9
|
|
Amendment No. 7 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated January 13, 2012 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 17, 2012, File No. 001-34046).
|
3.10
|
|
Amendment No. 8 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated August 1, 2012 (incorporated by reference to Exhibit 3.10 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on August 2, 2012, File No. 001-34046).
|
3.11
|
|
Amendment No. 9 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated December 12, 2012 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-34046).
|
3.12
|
|
Amendment No. 10 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 1, 2013 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
|
Exhibit
Number
|
|
Description
|
3.13
|
|
Amendment No. 11 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 3, 2014 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2014, File No. 001-34046).
|
3.14
|
|
Amendment No. 12 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated November 25, 2014 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on November 25, 2014, File No. 001-34046).
|
3.15
|
|
Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
|
3.16
|
|
Second Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated December 12, 2012 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-34046).
|
4.1
|
|
Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
|
4.2
|
|
Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
|
4.3
|
|
First Supplemental Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
|
4.4
|
|
Form of 5.375% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
|
4.5
|
|
Fifth Supplemental Indenture, dated as of August 14, 2013, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 14, 2013, File No. 001-34046).
|
4.6
|
|
Form of 4.000% Senior Notes due 2022 (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
|
4.7
|
|
Form of 2.600% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 14, 2013, File No. 001-34046).
|
4.8
|
|
Sixth Supplemental Indenture, dated as of March 20, 2014, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
|
4.9
|
|
Form of 5.450% Senior Notes due 2044 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
|
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).
|
Exhibit
Number
|
|
Description
|
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
|
|
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).
|
10.9
|
|
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).
|
10.10
|
|
Form of Commodity Price Swap Agreement (filed as Exhibit 10.3 to the Partnership’s Form 10-Q for the quarter ended March 31, 2010).
|
10.11‡
|
|
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).
|
10.12‡
|
|
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).
|
10.13‡
|
|
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).
|
10.14†
|
|
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).
|
10.15
|
|
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).
|
10.16
|
|
Indemnification Agreement, dated March 1, 2013, between Western Gas Holdings, LLC and Anadarko E&P Onshore LLC (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
|
10.17
|
|
Third Amended and Restated Indemnification Agreement, dated March 1, 2013, between Western Gas Holdings, LLC and Western Gas Resources, Inc. (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
|
10.18
|
|
Assignment of Indemnification Agreement, dated April 1, 2013, between Anadarko USH2 LLC and Anadarko E&P Onshore LLC (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on August 1, 2013, File No. 001-34046).
|
10.19
|
|
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).
|
10.20
|
|
First Amendment to the Third Amended and Restated Indemnification Agreement, dated March 3, 2014, between Western Gas Holdings, LLC and Western Gas Resources, Inc. (incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2014, File No. 001-34046).
|
10.21
|
|
USH2 Indemnification Agreement, dated March 3, 2014, Western Gas Holdings, LLC and USH2 LLC (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2014, File No. 001-34046).
|
Exhibit
Number
|
|
Description
|
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.
|
12.1*
|
|
Ratio of Earnings to Fixed Charges.
|
21.1*
|
|
List of Subsidiaries of Western Gas Partners, LP.
|
23.1*
|
|
Consent of KPMG LLP.
|
31.1*
|
|
Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
31.2*
|
|
Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
32.1**
|
|
Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
101.INS*
|
|
XBRL Instance Document
|
101.SCH*
|
|
XBRL Schema Document
|
101.CAL*
|
|
XBRL Calculation Linkbase Document
|
101.DEF*
|
|
XBRL Definition Linkbase Document
|
101.LAB*
|
|
XBRL Label Linkbase Document
|
101.PRE*
|
|
XBRL Presentation Linkbase Document
|
*
|
Filed herewith
|
**
|
Furnished herewith
|
#
|
Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.
|
†
|
Portions of this exhibit, which was previously filed with the Securities and Exchange Commission, were omitted pursuant to a request for confidential treatment. The omitted portions were filed separately with the Securities and Exchange Commission.
|
‡
|
Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.
|
|
WESTERN GAS PARTNERS, LP
|
|
|
February 26, 2015
|
|
|
|
|
/s/ Benjamin M. Fink
|
|
Benjamin M. Fink
Senior Vice President, Chief Financial Officer and Treasurer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
Signature
|
Title (Position with Western Gas Holdings, LLC)
|
|
|
/s/ Robert G. Gwin
|
Chairman and Director
|
Robert G. Gwin
|
|
|
|
/s/ Donald R. Sinclair
|
President, Chief Executive Officer and Director
|
Donald R. Sinclair
|
|
|
|
/s/ Benjamin M. Fink
|
Senior Vice President, Chief Financial Officer and Treasurer
|
Benjamin M. Fink
|
|
|
|
/s/ Charles A. Meloy
|
Director
|
Charles A. Meloy
|
|
|
|
/s/ Robert K. Reeves
|
Director
|
Robert K. Reeves
|
|
|
|
/s/ Steven D. Arnold
|
Director
|
Steven D. Arnold
|
|
|
|
/s/ Milton Carroll
|
Director
|
Milton Carroll
|
|
|
|
/s/ James R. Crane
|
Director
|
James R. Crane
|
|
|
|
/s/ David J. Tudor
|
Director
|
David J. Tudor
|
|
|
|
|
|
PAGE
|
|
EXHIBIT A -
|
DEDICATED AREAS AND WELLS
|
30
|
|
||
EXHIBIT B -
|
GAS QUALITY REQUIREMENTS
|
31
|
|
||
EXHIBIT C -
|
RECEIPT POINT(S)
|
33
|
|
||
EXHIBIT D -
|
DELIVERY POINT(S)
|
60
|
|
||
EXHIBIT E -
|
NOMINATION, CONFIRMATION AND BALANCING PROCEDURES
|
61
|
|
||
EXHIBIT F -
|
CURTAILMENT PROCEDURES
|
64
|
|
Payment to be made according to invoice and if no instructions to:
|
Kerr-McGee Gathering LLC
Attention: Contract Administration
1099 18th Street, Suite 1800
Denver, CO 80202-1918
Telephone: (720) 929-6000
Telecopy: (720) 929-3906
|
Nomination and Scheduling:
|
Kerr-McGee Gathering LLC
Attention: Gas Control
1099 18
th
Street, Suite 1800
Denver, CO 80202
Telephone: (720) 929-6445
Telecopy: (720) 929-7445
|
Pipeline Emergencies:
|
Telephone: (303) 659-5922
|
Audit:
|
Kerr-McGee Gathering LLC
Attention: Midstream Audit
1099 18
th
Street, Suite 1800
Denver, CO 80202-1918
Telephone: (720) 929-6000
Telecopy: (720) 929-3906
|
Notices:
|
Kerr-McGee Oil and Gas Onshore LP
Attention: Contract Administration 1099 18th Street, Suite 1800
Denver, CO 80202-1918
Telephone: (720) 929-6000
Telecopy: (720) 929-3906
|
GATHERER
|
SHIPPER
|
KERR-MCGEE GATHERING LLC
|
KERR-MCGEE OIL AND GAS ONSHORE LP
|
By:
/s/ Danny Rea
|
By:
/s/ James J. Kerr
|
Name: Danny Rea
|
Name: James J. Kerr
|
Title: Vice President
|
Title: VP Operations
|
Date: 7/27/10
|
Date: 7/27/10
|
1)
|
not contain more than five (5) grains of total sulphur) per one hundred (100) Cubic feet of Gas and shall not contain more than one-quarter (IA) of one (1) grain of hydrogen sulfide per one hundred (100) Cubic feet of Gas.
|
2)
|
not contain any measurable oxygen or mercury and shipper shall make every effort to keep Gas free from such contaminants.
|
3)
|
not contain more than two percent (2%) by volume of carbon dioxide.
|
4)
|
not contain more than two percent (2%) by volume of nitrogen.
|
5)
|
not contain more than four percent (4%) by volume of a combined total of inerts, carbon dioxide, nitrogen and other inert components, including helium, neon, and argon.
|
6)
|
be commercially free of water and hydrocarbons in a liquid state.
|
7)
|
have a temperature of not less than forty degrees (40°) Fahrenheit nor greater than one hundred twenty degrees (120°) Fahrenheit.
|
8)
|
contain no active bacteria or bacterial agent, including but not limited to sulphate reducing bacteria and acid producing bacteria, or any hazardous or toxic substances.
|
9)
|
have a total or gross Heating Value of not less than nine hundred fifty (950) Btu per cubic foot and not more than one thousand one hundred fifty (1400) Btu per cubic foot.
|
10)
|
be commercial in quality and free from any foreign materials such as dirt, dust, iron particles, crude oil, dark condensate, free water and other similar matter and substances which may be injurious to pipelines, meters or other facilities, or which may interfere with the processing, transmission or commercial utilization of said Gas.
|
11)
|
not contain mercaptans in excess of five parts per million (5 ppm) by volume.
|
12)
|
be free from all hazardous waste as that term is defined in the Resources Conservation and Recovery Act, 42 USC § 690.1, et seq.
|
13)
|
In addition to the water quality specifications set forth in this Agreement, Shipper shall be responsible to ensure that each Receipt Point is equipped with the necessary dehydration facilities to reduce the water content of the Gas received at such Receipt Point to seven pounds of water per one million cubic feet or less, unless, however, alternative arrangements have been made by Shipper with Gatherer to have Shipper’s Gas dehydrated downstream of such Receipt Point in existing facilities owned by Gatherer or other existing treating arrangements that Gatherer may have with Third Parties. If the water content of the Gas received at a Receipt Point exceeds seven pounds per one million cubic feet, then either the Heating Value so determined for such Receipt Point or the volume calculated for such Receipt Point shall be adjusted for water content at the “as delivered” conditions for the purpose of determining the Btu Content of Shipper’s Gas. If, however, Shipper delivers its Gas at a Receipt Point at seven pounds of water per one million cubic feet or less, then no such water content adjustments shall be made for purposes of determining the Btu Content of Shipper’s Gas.
|
METER
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METER NAME
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OPERATOR NAME
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***
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***
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SANDLIN OIL CORP
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***
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***
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SANDLIN OIL CORP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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SANDLIN OIL CORP
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***
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***
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SANDLIN OIL CORP
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***
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***
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SANDLIN OIL CORP
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***
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***
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ENCANA OIL & GAS (USA) INC.
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
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SANDLIN OIL CORP
|
***
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***
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SANDLIN OIL CORP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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SANDLIN OIL CORP
|
***
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***
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SANDLIN OIL CORP
|
***
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***
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SANDLIN OIL CORP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
METER
|
METER NAME
|
OPERATOR NAME
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
METER
|
METER NAME
|
OPERATOR NAME
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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METER
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METER NAME
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OPERATOR NAME
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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METER
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METER NAME
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OPERATOR NAME
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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METER
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METER NAME
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OPERATOR NAME
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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NOBLE ENERGY, INC.
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***
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***
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NOBLE ENERGY, INC.
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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NOBLE ENERGY, INC.
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***
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***
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NOBLE ENERGY, INC.
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KERR MCGEE OIL 7 GAS ONSHORE LP
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NOBLE ENERGY, INC.
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***
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***
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NOBLE ENERGY, INC.
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***
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KERR MCGEE OIL 7 GAS ONSHORE LP
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***
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KERR MCGEE OIL 7 GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL 7 GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL 7 GAS ONSHORE LP
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***
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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NOBLE ENERGY, INC
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NOBLE ENERGY, NC
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR-MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR-MCGEE OIL & GAS ONSHORE LP
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KERR-MCGEE OIL & GAS ONSHORE LP
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KERR-MCGEE OIL & GAS ONSHORE LP
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ENCANA OIL & GAS (USA) INC.
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KERR MCGEE OIL & GAS ONSHORE LP
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NOBLE ENERGY, INC
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OW & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL 7 GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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ENCANA OIL & GAS (USA) INC.
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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ENCANA OIL & GAS (USA) INC.
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K P KAUFFMAN COMPANY INC.
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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ENCANA OIL & GAS (USA) INC.
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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ENCANA OIL & GAS (USA) INC.
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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ENCANA OIL & GAS (USA) INC.
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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METER
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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ENCANA OIL & GAS (USA) INC.
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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H L WILLETT
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
|
ENCANA OIL & GAS (USA) INC.
|
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ENCANA OIL & GAS (USA) INC.
|
***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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METER
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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METER
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METER NAME
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OPERATOR NAME
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
|
ENCANA OIL & GAS (USA) INC.
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
|
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KERR MCGEE OIL & GAS ONSHORE LP
|
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
|
NOBLE ENERGY INC.
|
***
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***
|
NOBLE ENERGY, INC.
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
METER
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METER NAME
|
OPERATOR NAME
|
***
|
***
|
ENCANA OIL & GAS (USA) INC.
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
NOBLE ENERGY, INC.
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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SANDLIN OIL CORP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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ENCANA OIL & GAS (USA) INC.
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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ENCANA OIL & GAS (USA) INC.
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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METER
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METER NAME
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OPERATOR NAME
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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NOBLE ENERGY, INC
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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METER
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METER NAME
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OPERATOR NAME
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
|
ENCANA OIL & GAS (USA) INC.
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***
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***
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ENCANA OIL & GAS (USA) INC.
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ENCANA OIL & GAS (USA) INC.
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ENCANA OIL & GAS (USA) INC.
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ENCANA OIL & GAS (USA) INC.
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ENCANA OIL & GAS (USA) INC.
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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METER
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METER NAME
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OPERATOR NAME
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
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NOBLE ENERGY, INC.
|
***
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***
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ENCANA OIL & GAS (USA) INC.
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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ENCANA OIL & GAS (USA) INC.
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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METER
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METER NAME
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OPERATOR NAME
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KERR MCGEE OIL & GAS ONSHORE LP
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ENCANA OIL & GAS (USA) INC.
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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METER
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METER NAME
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OPERATOR NAME
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
|
ENCANA OIL & GAS (USA) INC.
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***
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***
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ENCANA OIL & GAS (USA) INC.
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***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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ENCANA OIL & GAS (USA) INC.
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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***
|
MERIT ENERGY COMPANY
|
***
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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ENCANA OIL & GAS (USA) INC.
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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KERR MCGEE OIL & GAS ONSHORE LP
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***
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KERR MCGEE OIL & GAS ONSHORE LP
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METER
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METER NAME
|
OPERATOR NAME
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
ENCANA OIL & GAS (USA) INC.
|
***
|
***
|
ENCANA OIL & GAS (USA) INC.
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
ENCANA OIL & GAS (USA) INC.
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
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KERR MCGEE OIL & GAS ONSHORE LP
|
***
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***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
PETROLEUM DEVELOPMENT CORPORATION
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
ENCANA OIL & GAS (USA) INC.
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
PETROLEUM DEVELOPMENT CORPORATION
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
ENCANA OIL & GAS (USA) INC.
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
METER
|
METER NAME
|
OPERATOR NAME
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
ENCANA OIL & GAS (USA) INC.
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
NOBLE ENERGY, INC
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
NOBLE ENERGY, INC
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
NOBLE ENERGY, INC
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
METER
|
METER NAME
|
OPERATOR NAME
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
NOBLE ENERGY, INC
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR-MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
***
|
***
|
ENCANA OIL & GAS (USA) INC.
|
***
|
***
|
KERR MCGEE OIL & GAS ONSHORE LP
|
I.
|
Section 3.
Service Level and Rates
Paragraphs A. and B. are amended by replacing "Fort Lupton Plant" with "Fort Lupton Plant and the Platte Valley Plant" wherever "Fort Lupton Plant" appears.
|
II.
|
Section 3.
Service Level and Rates
Paragraph C. is amended by adding the following sentence after the first sentence: "In addition, Shipper will pay Gatherer a processing fee of $*** per MMBtu for Gas delivered to the Platte Valley Plant Delivery Point."
|
III.
|
Section 6.
Special Provisions
Paragraph A. is amended by deleting the Definition of "Fort Lupton Plant" in its entirety and replacing it with the following:
|
IV.
|
Section 6.
Special Provisions
Paragraph A. is amended by adding the following Definition:
|
V.
|
Section 6.
Special Provisions
Paragraph A. is amended by deleting the Definition of "
Residue Gas
" in its entirety and replacing it with the following: "
Residue Gas
"
|
VI.
|
Section 6.
Special Provisions
Paragraph B. is deleted in its entirety and replaced with the following: "The Fort Lupton Plant allocation and the Platte Valley Plant allocation will be based on Shipper's respective pro rata shares of the volumes received at the plants. The Fort Lupton Plant volumes and the Platte Valley Plant volumes will be determined as the sum of all metered volumes leaving each plant respectively, including but not limited to volumes measured at fuel, flare, Plant Products and Residue Gas meters. Residue Gas will be returned to Shipper for its account at the tailgate of the Fort Lupton Plant and the tailgate of the Platte Valley Plant after all Heating Value reductions incidental to the processing."
|
VII.
|
EXHIBIT D to the Agreement,
DELIVERY POINTS
, is amended by deleting the following Delivery Point under the heading "
Gas
" in its entirety:
|
VIII.
|
EXHIBIT D to the Agreement,
DELIVERY POINTS
, is amended to add the following Delivery Point under the heading "
Plant Products
:"
|
KERR-MCGEE GATHERING LLC
|
KERR-MCGEE OIL & GAS ONSHORE LP
|
•
|
AKA – Gilcrest inlet
|
•
|
WGR Asset Holding Company LLC – Wattenberg Plant inlet
|
•
|
DCP – Hambert
|
•
|
DCP – Spindle inlet
|
•
|
Kerr-McGee Gathering LLC – Fort Lupton Plant Reside Gas tailgate
|
•
|
Kerr-McGee Gathering LLC – Fuel Gas delivery meter to Shipper’s oil polishing facility
|
•
|
Kerr-McGee Gathering LLC – Platte Valley Plant Inlet
|
•
|
Kerr-McGee Gathering LLC – Fort Lupton Plant Products tailgate meter
|
•
|
Kerr-McGee Gathering LLC – Platte Valley Plant Products tailgate meter
|
•
|
Kerr-McGee Gathering LLC operated field condensate collection point
|
•
|
WGR Asset Holding Company LLC – Wattenberg Plant tailgate liquid meter
|
KERR-MCGEE GATHERING LLC
|
KERR-MCGEE OIL AND GAS ONSHORE LP
|
|
|
By:
/s/ Michael M. Ross
|
By:
/s/ Craig R. Walters
|
|
|
Name: Michael M. Ross
|
Name: Craig R. Walters
|
|
|
Title: General Manager
|
Title: Director, Wattenberg
|
|
|
Year Ended December 31,
|
||||||||||||||||||
thousands
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income before income taxes
|
|
$
|
392,585
|
|
|
$
|
287,798
|
|
|
$
|
169,957
|
|
|
$
|
239,011
|
|
|
$
|
178,450
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges
|
|
86,824
|
|
|
63,903
|
|
|
48,422
|
|
|
30,993
|
|
|
19,292
|
|
|||||
Distributions from equity investees
|
|
81,022
|
|
|
22,136
|
|
|
20,660
|
|
|
15,999
|
|
|
10,973
|
|
|||||
Amortization of capitalized interest
|
|
1,687
|
|
|
814
|
|
|
479
|
|
|
294
|
|
|
256
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Equity income, net
|
|
57,836
|
|
|
22,948
|
|
|
16,042
|
|
|
11,261
|
|
|
7,628
|
|
|||||
Capitalized interest
|
|
9,832
|
|
|
11,945
|
|
|
6,196
|
|
|
420
|
|
|
—
|
|
|||||
Net income before taxes attributable to noncontrolling interests
|
|
14,025
|
|
|
10,816
|
|
|
14,890
|
|
|
14,103
|
|
|
11,005
|
|
|||||
Earnings
|
|
$
|
480,425
|
|
|
$
|
328,942
|
|
|
$
|
202,390
|
|
|
$
|
260,513
|
|
|
$
|
190,338
|
|
Fixed charges:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, including capitalized interest
|
|
$
|
86,598
|
|
|
$
|
63,742
|
|
|
$
|
48,256
|
|
|
$
|
30,765
|
|
|
$
|
18,794
|
|
Interest component of rent expense
|
|
226
|
|
|
161
|
|
|
166
|
|
|
228
|
|
|
498
|
|
|||||
Fixed charges
|
|
$
|
86,824
|
|
|
$
|
63,903
|
|
|
$
|
48,422
|
|
|
$
|
30,993
|
|
|
$
|
19,292
|
|
Ratio of earnings to fixed charges
|
|
5.5x
|
|
|
5.1x
|
|
|
4.2x
|
|
|
8.4x
|
|
|
9.9x
|
|
1.
|
I have reviewed this annual report on Form 10-K of Western Gas Partners, LP (the “registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
/s/ Donald R. Sinclair
|
|
Donald R. Sinclair
President and Chief Executive Officer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
1.
|
I have reviewed this annual report on Form 10-K of Western Gas Partners, LP (the “registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
/s/ Benjamin M. Fink
|
|
Benjamin M. Fink
Senior Vice President, Chief Financial Officer and Treasurer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
(1)
|
the annual report on Form 10-K of the Partnership for the period ending
December 31, 2014
, 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 26, 2015
|
|
|
|
|
|
|
|
/s/ Donald R. Sinclair
|
|
|
Donald R. Sinclair
|
|
|
President and Chief Executive Officer
|
|
|
Western Gas Holdings, LLC
|
|
|
(as general partner of Western Gas Partners, LP)
|
|
|
|
February 26, 2015
|
|
|
|
|
|
|
|
/s/ Benjamin M. Fink
|
|
|
Benjamin M. Fink
|
|
|
Senior Vice President, Chief Financial Officer and Treasurer
|
|
|
Western Gas Holdings, LLC
|
|
|
(as general partner of Western Gas Partners, LP)
|