☒
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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☐
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Commission file number:
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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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Western Midstream Partners, LP
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001-35753
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Delaware
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46-0967367
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Western Midstream Operating, LP
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001-34046
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Delaware
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26-1075808
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Address of principal executive offices:
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Zip Code:
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Registrant’s telephone number, including area code:
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Western Midstream Partners, LP
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1201 Lake Robbins Drive
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The Woodlands,
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Texas
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77380
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(832)
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636-6000
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Western Midstream Operating, LP
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1201 Lake Robbins Drive
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The Woodlands,
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Texas
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77380
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(832)
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636-6000
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Title of each class
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Trading symbol
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Name of exchange
on which registered |
Western Midstream Partners, LP
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Common units
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WES
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New York Stock Exchange
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Western Midstream Operating, LP
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None
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None
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None
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Western Midstream Partners, LP
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Yes
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þ
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No
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¨
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Western Midstream Operating, LP
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Yes
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þ
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No
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¨
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Western Midstream Partners, LP
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Yes
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¨
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No
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þ
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Western Midstream Operating, LP
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Yes
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¨
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No
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þ
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Western Midstream Partners, LP
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Yes
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þ
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No
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¨
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Western Midstream Operating, LP
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Yes
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þ
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No
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¨
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Western Midstream Partners, LP
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Yes
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þ
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No
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¨
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Western Midstream Operating, LP
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Yes
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þ
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No
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¨
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Western Midstream Partners, LP
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Large Accelerated Filer
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Accelerated Filer
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Non-accelerated Filer
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Smaller Reporting Company
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Emerging Growth Company
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þ
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☐
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☐
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☐
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☐
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Western Midstream Operating, LP
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Large Accelerated Filer
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Accelerated Filer
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Non-accelerated Filer
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Smaller Reporting Company
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Emerging Growth Company
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☐
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☐
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þ
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☐
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☐
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Western Midstream Partners, LP
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¨
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Western Midstream Operating, LP
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¨
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Western Midstream Partners, LP
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Yes
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☐
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No
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þ
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Western Midstream Operating, LP
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Yes
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☐
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No
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þ
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Western Midstream Partners, LP
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$6.2 billion
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Western Midstream Operating, LP
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None
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Western Midstream Partners, LP
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443,971,409
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Western Midstream Operating, LP
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None
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Item
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Page
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1 and 2.
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1A.
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1B.
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3.
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4.
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5.
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6.
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7.
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7A.
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8.
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9.
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9A.
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9B.
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Item
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Page
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10.
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11.
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12.
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13.
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14.
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15.
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16.
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Wholly
Owned and Operated |
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Operated
Interests |
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Non-Operated
Interests |
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Equity
Interests |
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Gathering systems (1)
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17
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2
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3
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2
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Treating facilities
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37
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3
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—
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3
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Natural-gas processing plants/trains
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25
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3
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—
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5
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NGLs pipelines
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2
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—
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—
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4
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Natural-gas pipelines
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5
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—
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—
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1
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Crude-oil pipelines
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3
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1
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—
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3
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(1)
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Includes the DBM water systems.
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Area
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Asset Type
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Miles of Pipeline (1)
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Approximate Number of Active Receipt Points (1)
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Compression (HP) (1) (2)
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Processing or Treating Capacity (MMcf/d) (1)
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Processing, Treating, or Disposal Capacity (MBbls/d) (1)
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Average Gathering, Processing, Treating, and Transportation Throughput (MMcf/d) (3)
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Average Gathering, Treating, Transportation, and Disposal Throughput (MBbls/d) (3)
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Rocky Mountains
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Gathering, Processing, and Treating
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7,198
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|
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3,463
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617,150
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3,720
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|
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194
|
|
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2,323
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|
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118
|
|
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Transportation
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2,199
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|
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31
|
|
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—
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—
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—
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87
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60
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Texas / New Mexico
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Gathering, Processing, Treating, and Disposal
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3,838
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2,040
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774,334
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1,825
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1,386
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1,765
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792
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Transportation
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2,438
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38
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—
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—
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—
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142
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249
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North-central Pennsylvania
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Gathering
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146
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59
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9,660
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—
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—
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106
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—
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Total
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15,819
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5,631
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1,401,144
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5,545
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1,580
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4,423
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1,219
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(1)
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All system metrics are presented on a gross basis and include owned, rented, and leased compressors at certain facilities. Includes horsepower associated with liquid pump stations. Includes bypass capacity at the DJ Basin and West Texas complexes.
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(2)
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Excludes compression horsepower for transportation.
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(3)
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Includes throughput for all assets owned and ownership interests accounted for by us under the equity method of accounting. For further details see Properties below.
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•
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Capitalizing on organic growth opportunities. We expect to grow certain of our systems organically over time by meeting our customers’ midstream service needs that arise from drilling activity in our areas of operation. We continually evaluate economically attractive organic expansion opportunities in existing or new areas of operation that allow us to leverage our infrastructure, operating expertise, and customer relationships to meet new or increased demand of our services.
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•
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Increasing third-party volumes to our systems. We continue to actively market our midstream services to, and pursue strategic relationships with, third-party customers to attract additional volumes and/or expansion opportunities.
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•
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Controlling our operating, capital, and administrative costs. We continue to optimize and maximize the operability of our existing assets to realize cost and capital savings. As a result of the recent transformation of our workforce that historically maintained dual upstream and midstream responsibilities into a solely midstream-focused organization, we believe that we will drive operational, capital, and administrative cost efficiencies throughout the organization.
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•
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Maintaining investment grade metrics. We intend to operate with leverage metrics and distribution coverage levels that are consistent with other investment-grade credits in our sector. Maintaining leverage ratios that are within the industry-standard investment-grade credit metrics positions us to pursue strategic acquisitions and to fund large growth projects at a lower cost of capital, which enhances our accretion and overall return.
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•
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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 fee-based contract structures designed to mitigate direct exposure to commodity prices.
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•
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Substantial presence in basins with historically strong producer economics. Certain of our systems are in areas, such as the Delaware and DJ Basins, which historically have seen robust producer activity and are considered to have some of the most favorable producer returns for onshore North America. Our assets in these areas are capable of servicing hydrocarbon production that contains natural gas, crude oil, condensate, and NGLs. Our systems in the Delaware Basin also include significant produced-water takeaway capacity, which positions us as a full-service midstream provider in the basin.
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•
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Well-positioned and well-maintained assets. We believe that our asset portfolio, located in geographically diverse areas of operation, provides us with opportunities to expand and attract additional volumes to our systems from multiple productive reservoirs. Moreover, our portfolio consists of high-quality, well-maintained assets for which we have implemented modern processing, treating, measurement, and operating technologies.
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•
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Commodity-price and volumetric-risk mitigation. We believe a substantial majority of our cash flows are protected from direct exposure to commodity-price volatility, as 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil, NGLs, and produced-water throughput (excluding equity investments) were serviced under fee-based contracts for the year ended December 31, 2019. In addition, we mitigate volumetric risk by entering into contracts with cost-of-service structures and/or minimum-volume commitments. For the year ended December 31, 2019, 65% of our natural-gas throughput and 78% of our crude-oil, NGLs, and produced-water throughput were supported by either minimum-volume commitments with associated deficiency payments or cost-of-service commitments.
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•
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Affiliation with Occidental. We believe Occidental is motivated to promote and support the successful execution of our business plan. We continue leveraging our long-standing relationship with Occidental by sizing and planning growth initiatives in a manner that highlights the strength of our asset portfolio vis a vis Occidental’s upstream development plans. Continuing our relationship with Occidental enables us to pursue more capital-efficient projects that enhance the overall value of our business. See WES and WES Operating’s Relationship with Occidental Petroleum Corporation below.
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•
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Liquidity to pursue expansion and acquisition opportunities. We believe our operating cash flows, borrowing capacity, long-dated debt maturity profile, long-term relationships, and reasonable access to capital markets provide us with the liquidity to competitively pursue acquisition and expansion opportunities and to execute our strategy across capital market cycles. As of December 31, 2019, there was $1.6 billion in available borrowing capacity under the RCF.
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•
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Gathering. At the initial stages of the midstream value chain, a network of typically smaller diameter pipelines known as gathering systems directly connect to wellheads or production facilities in the area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing, if necessary. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow gathering of additional production without significant incremental capital expenditures.
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•
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Stabilization. Stabilization is a process that separates the heavier hydrocarbons (which are also valuable commodities) that are sometimes found in natural gas, typically referred to as “liquids-rich” natural gas, from the lighter components by using a distillation process, adding heat, or by reducing the pressure and allowing the more volatile components to flash from the liquid phase to the gas phase.
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•
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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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•
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Treating and dehydration. To the extent that gathered natural gas contains water vapor or contaminants, such as carbon dioxide or hydrogen sulfide, it is dehydrated to remove the saturated water and treated to separate the carbon dioxide or hydrogen sulfide from the gas stream.
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•
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Processing. The principal components of natural gas are methane and ethane, but often the natural gas also contains varying amounts of heavier NGLs and contaminants, such as water and carbon dioxide, sulfur compounds, nitrogen, or helium. Natural gas is processed to remove unwanted contaminants that would interfere with pipeline transportation or use of the natural gas and to separate those hydrocarbon liquids from the gas that have higher value as NGLs. The removal and separation of individual hydrocarbons through processing is possible due to differences in molecular weight, boiling point, vapor pressure, and other physical characteristics.
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•
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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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•
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Storage, transportation, and marketing. Once the raw natural gas has been treated or processed and the raw NGL mix has been fractionated into individual NGL components, the natural gas and NGL components are stored, transported, and marketed to end-use markets. Each pipeline system typically has storage capacity located throughout the pipeline network or at major market centers to better accommodate seasonal demand and daily supply-demand shifts. We do not currently offer storage services.
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•
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Gathering. Crude-oil gathering assets provide the link between crude-oil production gathered at the well site or nearby collection points and crude-oil terminals, storage facilities, long-haul crude-oil pipelines, and refineries. Crude-oil gathering assets generally consist of a network of small-diameter pipelines that are connected directly to the well site or central receipt points and deliver into large-diameter trunk lines. To the extent there are not enough volumes to justify construction of or connection to a pipeline system, crude oil can also be trucked from a well site to a central collection point.
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•
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Stabilization. Crude-oil stabilization assets process crude oil to meet downstream vapor pressure specifications. Crude-oil delivery points, including crude-oil terminals, storage facilities, long-haul crude-oil pipelines, and refineries, often have specific requirements for vapor pressure and temperature, and for the amount of sediment and water that can be contained in any crude oil delivered to them.
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•
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Gathering. Produced water often accounts for the largest byproduct stream associated with the onshore production of crude oil and natural gas. Produced-water gathering assets provide the link between well sites or nearby collection points and disposal facilities.
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•
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Disposal. As a natural byproduct of crude-oil and natural-gas production, produced water must be recycled or disposed of in order to maintain production. Produced-water disposal systems remove hydrocarbon products and other sediments from the produced water and re-inject the produced water utilizing permitted disposal wells in compliance with applicable regulations.
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•
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Fee-based. Under fee-based arrangements, the service provider typically receives a fee for each unit of (i) natural gas, NGLs, or crude-oil gathered, treated, processed, and/or transported, or (ii) produced water gathered and disposed of, at its facilities. As a result, the per-unit price received by the service provider does not vary with commodity-price changes, thereby minimizing the service provider’s direct commodity-price risk exposure.
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•
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Percent-of-proceeds, percent-of-value, or percent-of-liquids. Percent-of-proceeds, percent-of-value, or percent-of-liquids arrangements may be used for gathering and processing services. Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue gas and/or NGLs or a percentage of the actual residue gas and/or NGLs at the tailgate. These types of arrangements expose the service provider 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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•
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Keep-whole. Keep-whole arrangements may be used for processing services. Under these arrangements, a customer provides liquids-rich gas volumes to the service provider for processing. The service provider is obligated to return the equivalent gas volumes to the customer subsequent to processing. Due to the use and loss of volumes in processing, the service provider must purchase additional volumes to compensate the customer. In these arrangements, the service provider receives all or a portion of the NGLs produced in consideration for the service provided. These types of arrangements expose the service provider to commodity-price exposure associated with the cost of purchased keep-whole volumes and the sales value of the retained NGLs.
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Location
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Asset
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Type
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Processing / Treating Plants
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Processing / Treating Capacity (MMcf/d) (1)
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Processing / Treating Capacity (MBbls/d)
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Compressors
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Compression Horsepower
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Gathering Systems
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Pipeline Miles (2)
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Colorado
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DJ Basin complex (3)
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Gathering, Processing, & Treating
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15
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|
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1,480
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|
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39
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|
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155
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|
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375,962
|
|
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2
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|
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3,270
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Colorado
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DJ Basin oil system
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Gathering & Treating
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|
6
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|
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—
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|
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155
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|
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29
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|
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6,905
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|
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1
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|
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347
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Utah
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Chipeta (4)
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Processing
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3
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|
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790
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|
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—
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|
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12
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74,875
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|
|
—
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|
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2
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Total
|
|
|
|
|
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24
|
|
|
2,270
|
|
|
194
|
|
|
196
|
|
|
457,742
|
|
|
3
|
|
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3,619
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(1)
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Includes 160 MMcf/d of bypass capacity at the DJ Basin complex.
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(2)
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Includes 12 miles of transportation related to a crude-oil pipeline at the DJ Basin oil system.
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(3)
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The DJ Basin complex includes the Platte Valley, Fort Lupton, Fort Lupton JT, Hambert JT (currently inactive), Wattenberg, Lancaster Trains I and II, and Latham Train I processing plants, and the Wattenberg gathering system. Excludes 600 gpm of amine-treating capacity.
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(4)
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We are the managing member of and own a 75% interest in Chipeta, which owns the Chipeta processing complex.
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•
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Customers. For the year ended December 31, 2019, Occidental’s production represented 62% of the DJ Basin complex throughput and the two-largest third-party customers provided 19% of the throughput. Effective December 31, 2019, Kerr-McGee Oil & Gas Onshore, LP, a subsidiary of Occidental, and Kerr-McGee Gathering LLC (“KMGG”), a subsidiary of WES Operating, entered into an amendment to the DJ gas-gathering agreement to provide for the extension of gathering services by KMGG to gas produced by a subsidiary of Occidental in Weld County, Colorado, in the DJ Basin for a primary term ending August 2029. This agreement provides new acreage dedications covering approximately 21,000 acres.
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•
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Supply. The DJ Basin complex is supplied primarily by the Wattenberg field. There were 1,806 active receipt points connected to the DJ Basin complex as of December 31, 2019. Occidental has dedicated to WES approximately 640,000 gross acres within the DJ Basin.
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•
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Delivery points. As of December 31, 2019, the DJ Basin complex had various delivery-point interconnections with DCP Midstream LP’s (“DCP”) gathering and processing system for gas not processed within the DJ Basin complex. The DJ Basin complex is connected to the Colorado Interstate Gas Company LLC’s pipeline (“CIG pipeline”) and Xcel Energy’s residue pipelines for natural-gas residue takeaway and to Overland Pass Pipeline Company LLC’s pipeline and FRP’s pipeline for NGLs takeaway. In addition, the NGLs fractionator at the Platte Valley plant and associated truck-loading facility provides access to local NGLs markets.
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•
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Customers. For the year ended December 31, 2019, all of the DJ Basin oil system throughput was from Occidental’s production.
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•
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Supply. The DJ Basin oil system, which is supplied primarily by the Wattenberg field, gathers high-vapor-pressure crude oil and delivers it to the COSF. The COSF includes two 250,000 barrel crude-oil storage tanks and connectivity to local storage owned by Energy Transfer LP (“ET”).
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•
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Delivery points. The COSF has market access to the White Cliffs pipeline, Saddlehorn pipeline, and rail-loading facilities in Tampa, Colorado, and local markets.
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•
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Customers. For the year ended December 31, 2019, Occidental’s production represented 66% of the Chipeta complex throughput and the two largest third-party customers provided 27% of the throughput.
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•
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Supply. The Chipeta complex is well positioned to access Occidental and third-party production in the Uinta Basin. Occidental has dedicated to WES approximately 170,000 gross acres in the Uinta Basin. Chipeta’s inlet is connected to Occidental’s Greater Natural Buttes gathering system, the Dominion Energy Questar Pipeline, LLC system (“Questar pipeline”), and Three Rivers Gathering, LLC’s system, which is owned by MPLX LP (“MPLX”).
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•
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Delivery points. The Chipeta plant delivers NGLs via the GNB NGL pipeline to Enterprise Products Partners LP’s (“Enterprise”) Mid-America Pipeline Company pipeline (“MAPL pipeline”), which provides transportation through Enterprise’s Seminole pipeline (“Seminole pipeline”) and TEP’s pipeline in West Texas, and ultimately to the NGLs fractionation and storage facilities in Mont Belvieu, Texas. The Chipeta plant has residue gas delivery points through the following pipelines that deliver residue gas to markets throughout the Rockies and Western United States:
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◦
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CIG pipeline;
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◦
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Questar pipeline; and
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◦
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Wyoming Interstate Company’s pipeline (“WIC pipeline”).
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Location
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Asset
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Type
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Processing / Treating Plants
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Processing / Treating Capacity (MMcf/d)
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Compressors
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Compression Horsepower
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Gathering Systems
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Pipeline Miles
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||||||
Northeast Wyoming
|
|
Bison
|
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Treating
|
|
3
|
|
|
450
|
|
|
9
|
|
|
14,645
|
|
|
—
|
|
|
—
|
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Northeast Wyoming
|
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Fort Union (1)
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Gathering & Treating
|
|
3
|
|
|
295
|
|
|
3
|
|
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5,454
|
|
|
1
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|
|
315
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Northeast Wyoming
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Hilight
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Gathering & Processing
|
|
2
|
|
|
60
|
|
|
34
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|
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36,554
|
|
|
1
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|
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1,124
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Southwest Wyoming
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|
Granger complex (2)
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Gathering & Processing
|
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4
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|
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520
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|
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41
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|
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44,967
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|
|
1
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|
|
741
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|
Southwest Wyoming
|
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Red Desert complex (3)
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Gathering & Processing
|
|
1
|
|
|
125
|
|
|
25
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|
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50,303
|
|
|
1
|
|
|
1,061
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|
Southwest Wyoming
|
|
Rendezvous (4)
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|
Gathering
|
|
—
|
|
|
—
|
|
|
5
|
|
|
7,485
|
|
|
1
|
|
|
338
|
|
Total
|
|
|
|
|
|
13
|
|
|
1,450
|
|
|
117
|
|
|
159,408
|
|
|
5
|
|
|
3,579
|
|
(1)
|
We have a 14.81% interest in Fort Union.
|
(2)
|
The Granger complex includes the “Granger straddle plant,” a refrigeration processing plant.
|
(3)
|
The Red Desert complex includes the Red Desert cryogenic processing plant, which currently is inactive, and the Patrick Draw cryogenic processing plant.
|
(4)
|
We have a 22% interest in the Rendezvous gathering system, which is operated by a third party.
|
•
|
Customers. Bison treating facility throughput was from one third-party customer as of December 31, 2019. In connection with Anadarko’s sale of the Powder River Basin coal-bed methane assets in 2015, Occidental still retains a commitment to Bison that extends through December 2020 for which we earn affiliate revenues.
|
•
|
Supply and delivery points. The Bison treating facility treats and compresses gas from coal-bed methane wells in the Powder River Basin of Wyoming. The Bison treating facility is directly connected to Fort Union’s pipeline and the Bison Pipeline operated by TransCanada Corporation.
|
•
|
Customers. One shipper holds a majority of the firm capacity on the Fort Union system. To the extent capacity on the system is not used by this customer, it is available to third parties under interruptible agreements.
|
•
|
Supply. Substantially all of Fort Union’s gas supply is comprised of coal-bed methane volumes from the Powder River Basin near Gillette, Wyoming, that are either produced or gathered by the customer noted above and its affiliates. These volumes are gathered and treated under contracts with minimum-volume commitments.
|
•
|
Delivery points. The Fort Union system delivers coal-bed methane gas to the hub in Glenrock, Wyoming, which accesses the following interstate pipelines:
|
◦
|
CIG pipeline;
|
◦
|
Tallgrass Interstate Gas Transmission system’s pipeline (“TIGT pipeline”); and
|
◦
|
WIC pipeline.
|
•
|
Customers. As of December 31, 2019, gas gathered and processed at the Hilight system was from third-party customers. The four-largest producers provided 70% of the system throughput for the year ended December 31, 2019.
|
•
|
Supply. The Hilight system serves the gas-gathering needs of several conventional producing fields in Johnson, Campbell, Natrona, and Converse Counties, Wyoming.
|
•
|
Delivery points. The Hilight plant delivers residue gas to our MIGC transmission line (see Transportation within these Items 1 and 2). Hilight is not connected to an active NGLs pipeline, resulting in all fractionated NGLs being sold locally through truck and rail loading facilities.
|
•
|
Customers. As of December 31, 2019, Granger complex throughput was from third-party customers, with the three-largest third-party customers providing 77% of the Granger complex throughput for the year ended December 31, 2019.
|
•
|
Supply. The Granger complex is supplied by the Moxa Arch and the Jonah and Pinedale Anticline fields. The Granger gas-gathering system had 580 active receipt points as of December 31, 2019.
|
•
|
Delivery points. Residue gas from the Granger complex can be delivered to the following major pipelines:
|
◦
|
CIG pipeline;
|
◦
|
Berkshire Hathaway Energy’s Kern River pipeline (“Kern River pipeline”) via a connect with MPLX’s Rendezvous pipeline (“Rendezvous pipeline”);
|
◦
|
Questar pipeline;
|
◦
|
Dominion Energy Overthrust Pipeline;
|
◦
|
The Williams Companies, Inc.’s Northwest Pipeline (“NWPL”);
|
◦
|
our OTTCO pipeline; and
|
◦
|
our Mountain Gas Transportation LLC pipeline.
|
•
|
Customers. For the year ended December 31, 2019, 70% of the Red Desert complex throughput was from the four-largest third-party customers and 1% was from Occidental.
|
•
|
Supply. The Red Desert complex gathers, compresses, treats, and processes natural gas and fractionates NGLs produced from the eastern portion of the Greater Green River Basin, providing service primarily to the Red Desert and Washakie Basins.
|
•
|
Delivery points. Residue from the Red Desert complex is delivered to the CIG and WIC pipelines, while NGLs are delivered to the MAPL pipeline and to truck- and rail-loading facilities.
|
•
|
Customers. As of December 31, 2019, Rendezvous system throughput primarily was from two shippers that have dedicated acreage to the system.
|
•
|
Supply and delivery points. The Rendezvous system provides high-pressure gathering service for gas from the Jonah and Pinedale Anticline fields and delivers to our Granger plant and MPLX’s Blacks Fork gas-processing plant, which connects to the Questar pipeline, NWPL, and the Kern River pipeline via the Rendezvous pipeline.
|
Location
|
|
Asset
|
|
Type
|
|
Processing / Treating Plants
|
|
Processing / Treating Capacity (MMcf/d) (1)
|
|
Processing / Treating / Disposal Capacity (MBbls/d)
|
|
Compressors / Pumps (2)
|
|
Compression Horsepower (2)
|
|
Gathering Systems
|
|
Pipeline Miles (3)
|
|||||||
West Texas / New Mexico
|
|
West Texas complex (4)
|
|
Gathering, Processing, & Treating
|
|
14
|
|
|
1,300
|
|
|
46
|
|
|
280
|
|
|
473,230
|
|
|
3
|
|
|
1,577
|
|
West Texas
|
|
DBM oil system (5)
|
|
Gathering & Treating
|
|
14
|
|
|
—
|
|
|
195
|
|
|
102
|
|
|
17,598
|
|
|
1
|
|
|
576
|
|
West Texas
|
|
DBM water systems
|
|
Gathering & Disposal
|
|
—
|
|
|
—
|
|
|
885
|
|
|
125
|
|
|
50,750
|
|
|
5
|
|
|
851
|
|
West Texas
|
|
Mi Vida (6)
|
|
Processing
|
|
1
|
|
|
200
|
|
|
—
|
|
|
4
|
|
|
20,000
|
|
|
—
|
|
|
—
|
|
West Texas
|
|
Ranch Westex (7)
|
|
Processing
|
|
2
|
|
|
125
|
|
|
—
|
|
|
2
|
|
|
10,090
|
|
|
—
|
|
|
6
|
|
East Texas
|
|
Mont Belvieu JV (8)
|
|
Processing
|
|
2
|
|
|
—
|
|
|
170
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
South Texas
|
|
Brasada complex
|
|
Gathering, Processing, & Treating
|
|
3
|
|
|
200
|
|
|
15
|
|
|
14
|
|
|
30,450
|
|
|
1
|
|
|
57
|
|
South Texas
|
|
Springfield system (9)
|
|
Gathering and Treating
|
|
3
|
|
|
—
|
|
|
75
|
|
|
107
|
|
|
172,216
|
|
|
2
|
|
|
771
|
|
Total
|
|
|
|
|
|
39
|
|
|
1,825
|
|
|
1,386
|
|
|
634
|
|
|
774,334
|
|
|
12
|
|
|
3,838
|
|
(1)
|
Includes 70 MMcf/d of bypass capacity at the West Texas complex.
|
(2)
|
Includes owned, rented, and leased compressors and compression horsepower.
|
(3)
|
Includes 18 miles of transportation related to the Ramsey Residue Lines (regulated by FERC) at the West Texas complex and 14 miles of transportation related to a crude-oil pipeline at the DBM oil system.
|
(4)
|
The West Texas complex includes the DBM complex and DBJV and Haley systems. Excludes 2,300 gpm of amine-treating capacity.
|
(5)
|
The DBM oil system includes three central production facilities and two ROTFs.
|
(6)
|
We own a 50% interest in Mi Vida, which owns a processing plant operated by a third party.
|
(7)
|
We own a 50% interest in Ranch Westex, which owns a processing plant operated by a third party.
|
(8)
|
We own a 25% interest in the Mont Belvieu JV, which owns two NGLs fractionation trains. A third party serves as the operator.
|
(9)
|
We own a 50.1% interest in the Springfield system and serve as the operator.
|
•
|
Customers. For the year ended December 31, 2019, Occidental’s production represented 41% of the West Texas complex throughput and the largest third-party customer provided 10% of the throughput.
|
•
|
Supply. Supply of gas and NGLs for the complex comes from production from the Delaware Sands, Avalon Shale, Bone Spring, Wolfcamp, and Penn formations in the Delaware Basin portion of the Permian Basin. Occidental has dedicated to WES approximately 530,000 gross acres within the Delaware Basin.
|
•
|
Delivery points. Avalon, Bone Spring, and Wolfcamp gas is dehydrated, compressed, and delivered to the Ranch Westex and Mi Vida plants (see below) and within the West Texas complex for processing, while lean gas is delivered into Enterprise GC, L.P.’s pipeline for ultimate delivery into ET’s Oasis pipeline (the “Oasis pipeline”). Residue gas from the West Texas complex is delivered to the Red Bluff Express pipeline and the Ramsey Residue Lines, which extend from the complex to the south and to the north, with both lines connecting with Kinder Morgan, Inc.’s interstate pipeline system. NGLs production is delivered into the Sand Hills pipeline, Lone Star NGL LLC’s pipeline (“Lone Star pipeline”), and EPIC Y-Grade Pipeline, LP’s NGL pipeline.
|
•
|
Customers. As of December 31, 2019, DBM oil system throughput was from Occidental and one third-party producer. For the year ended December 31, 2019, Occidental’s production represented 94% of the DBM oil system throughput. All parties ship pursuant to a tariff on file with the Texas Railroad Commission.
|
•
|
Supply. The DBM oil system is supplied from production from the Delaware Basin portion of the Permian Basin.
|
•
|
Delivery points. Crude oil treated at the DBM oil system and a third-party treating facility is delivered from the system into Plains All American Pipeline.
|
•
|
Customers. As of December 31, 2019, DBM water systems throughput was from Occidental and numerous third-party producers. Occidental’s production represented 82% of the throughput for the year ended December 31, 2019.
|
•
|
Supply. Supply of produced water for the systems comes from crude-oil production from the Delaware Basin portion of the Permian Basin.
|
•
|
Disposal. The DBM water systems gather and dispose produced water via subsurface injection or offload to third-party service providers. The systems’ injection wells are located in Loving, Reeves, and Ward Counties in Texas.
|
•
|
Customers. As of December 31, 2019, Mi Vida plant throughput was from Occidental and one third-party customer.
|
•
|
Supply and delivery points. The Mi Vida plant receives volumes from the West Texas complex and ET’s gathering system. Residue gas from the Mi Vida plant is delivered to the Oasis pipeline or Transwestern Pipeline Company LLC’s pipeline (“Transwestern pipeline”). NGLs production is delivered to the Lone Star pipeline.
|
•
|
Customers. As of December 31, 2019, Ranch Westex plant throughput was from Occidental and one third-party customer.
|
•
|
Supply and delivery points. The Ranch Westex plant receives volumes from the West Texas complex and Crestwood Equity Partners LP’s gathering system. Residue gas from the Ranch Westex plant is delivered to the Oasis pipeline or Transwestern pipeline and NGLs production is delivered to the Lone Star pipeline.
|
•
|
Customers. The Mont Belvieu JV does not contract with customers directly, but is allocated volumes from Enterprise based on the available capacity of the other trains at Enterprise’s NGLs 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, including the Seminole pipeline, Skelly-Belvieu Pipeline Company, LLC’s pipeline, TEP, and Panola pipeline (see Transportation within these Items 1 and 2). Individual NGLs are delivered to end users either through customer-owned pipelines that are connected to nearby petrochemical plants or via export terminals.
|
•
|
Customers. Brasada complex throughput was from one third-party customer as of December 31, 2019.
|
•
|
Supply. Supply of gas and NGLs is sourced from throughput gathered by the Springfield system.
|
•
|
Delivery points. The facility delivers residue gas to the Eagle Ford Midstream system operated by NET Midstream, LLC. Stabilized condensate is delivered to Plains All American Pipeline and NGLs are delivered to the Enterprise-operated South Texas NGL Pipeline System.
|
•
|
Customers. Springfield system throughput was from numerous third-party customers as of December 31, 2019.
|
•
|
Supply. Supply of gas and oil is sourced from third-party production in the Eagleford shale.
|
•
|
Delivery points. The gas-gathering system delivers rich gas to our Brasada complex, the Targa Resources Corp.-owned Raptor processing plant, Sanchez Midstream Partners LP, and to processing plants operated by Enterprise, ET, and Kinder Morgan, Inc. The oil-gathering system has delivery points to Plains All American Pipeline, Kinder Morgan, Inc.’s Double Eagle Pipeline, Hilcorp Energy Company’s Harvest Pipeline, and NuStar Energy L.P.’s Pipeline.
|
Location
|
|
Asset
|
|
Type
|
|
Compressors
|
|
Compression Horsepower
|
|
Gathering Systems
|
|
Pipeline Miles
|
||||
North-central Pennsylvania
|
|
Marcellus (1)
|
|
Gathering
|
|
7
|
|
|
9,660
|
|
|
3
|
|
|
146
|
|
(1)
|
We own a 33.75% interest in the Marcellus Interest gathering systems.
|
•
|
Customers. As of December 31, 2019, the Marcellus Interest gathering systems had two priority shippers. The largest producer provided 80% of the throughput for the year ended December 31, 2019. Capacity not used by priority shippers is available to third parties as determined by the operating partner, Alta Resources Development, LLC.
|
•
|
Supply and delivery points. The Marcellus Interest gathering systems are well-positioned to serve dry-gas production from the Marcellus shale. The Marcellus Interest gathering systems have access to Transcontinental Gas Pipe Line Company, LLC’s pipeline.
|
Location
|
|
Asset
|
|
Type
|
|
Pipeline Miles
|
|
Colorado, Kansas, Oklahoma
|
|
White Cliffs (1) (2)
|
|
Oil & NGLs
|
|
1,054
|
|
Wyoming, Colorado, Kansas, Oklahoma
|
|
Saddlehorn (1) (3)
|
|
Oil
|
|
600
|
|
Utah
|
|
GNB NGL (1)
|
|
NGLs
|
|
33
|
|
Northeast Wyoming
|
|
MIGC (1)
|
|
Gas
|
|
243
|
|
Southwest Wyoming
|
|
OTTCO
|
|
Gas
|
|
208
|
|
Southwest Wyoming
|
|
Wamsutter
|
|
Oil
|
|
61
|
|
Colorado, Oklahoma, Texas
|
|
FRP (1) (4)
|
|
NGLs
|
|
447
|
|
Texas, Oklahoma
|
|
TEG (4)
|
|
NGLs
|
|
191
|
|
Texas
|
|
TEP (1) (4)
|
|
NGLs
|
|
593
|
|
Texas
|
|
Whitethorn LLC (5)
|
|
Oil
|
|
416
|
|
Texas
|
|
Panola (1) (6)
|
|
NGLs
|
|
248
|
|
Texas
|
|
Cactus II (1) (7)
|
|
Oil
|
|
461
|
|
Texas
|
|
Red Bluff Express (1) (8)
|
|
Gas
|
|
82
|
|
Total
|
|
|
|
|
|
4,637
|
|
(1)
|
White Cliffs, Saddlehorn, GNB NGL, MIGC, FRP, TEP, Panola, Cactus II, and Red Bluff Express are regulated by FERC.
|
(2)
|
We own a 10% interest in the White Cliffs pipeline, which is operated by a third party.
|
(3)
|
We own a 20% interest in the Saddlehorn pipeline, which is operated by a third party.
|
(4)
|
We own a 20% interest in TEG and TEP and a 33.33% interest in FRP. All three systems are operated by third parties.
|
(5)
|
We own a 20% interest in Whitethorn, which is operated by a third party.
|
(6)
|
We own a 15% interest in the Panola pipeline, which is operated by a third party.
|
(7)
|
We own a 15% interest in the Cactus II pipeline, which is operated by a third party.
|
(8)
|
We own a 30% interest in the Red Bluff Express pipeline, which is operated by a third party.
|
•
|
Customers. The White Cliffs pipeline had multiple committed shippers, including Occidental, as of December 31, 2019. Other parties may also ship on the White Cliffs pipeline at FERC-based rates. The White Cliffs dual-pipeline system provides crude-oil and NGL takeaway capacity of approximately 190 MBbls/d from Platteville, Colorado, to Cushing, Oklahoma. In 2019, one of the pipelines was converted from crude-oil service to NGL Y-grade service.
|
•
|
Supply. The White Cliffs pipeline is supplied by production from the DJ Basin. At the point of origin, there is a storage facility adjacent to a truck-unloading facility.
|
•
|
Delivery points. The White Cliffs pipeline delivery point is ET’s storage facility in Cushing, Oklahoma, a major crude-oil marketing center, which ultimately delivers to Gulf Coast and mid-continent refineries.
|
•
|
Customers. The Saddlehorn pipeline had multiple committed shippers, including Occidental, as of December 31, 2019. Other parties may also ship on the Saddlehorn pipeline at FERC-based rates.
|
•
|
Supply. The Saddlehorn pipeline has multiple origin points including: Cheyenne, Wyoming; Ft. Laramie, Wyoming; Carr, Colorado; and Platteville, Colorado. Saddlehorn is supplied by the DJ Basin and basins that connect to a Wyoming access point.
|
•
|
Delivery points. The Saddlehorn pipeline delivers crude oil and condensate to storage facilities in Cushing, Oklahoma.
|
•
|
Customers. Occidental was the only shipper on the GNB NGL pipeline as of December 31, 2019. The GNB NGL pipeline provides capacity at the posted FERC-based rates.
|
•
|
Supply. The GNB NGL pipeline receives NGLs from Chipeta’s gas-processing facility and MPLX’s Stagecoach/Iron Horse gas-processing complex.
|
•
|
Delivery points. The GNB NGL pipeline delivers NGLs to the MAPL pipeline, which provides transportation through the Seminole pipeline and TEP in West Texas, and ultimately to NGLs fractionation and storage facilities in Mont Belvieu, Texas.
|
•
|
Customers. Occidental was the largest firm shipper on the MIGC system, with 56% of the throughput for the year ended December 31, 2019. The remaining throughput on the MIGC system was from numerous third-party shippers. MIGC is certificated for 175 MMcf/d of firm-transportation capacity. All parties on the MIGC system ship pursuant to a tariff on file with FERC.
|
•
|
Supply. MIGC receives gas from the Hilight system, Evolution Midstream’s Jewell plant, various coal-bed methane gathering systems in the Powder River Basin, and from WBI Energy Transmission, Inc. on the north end of the transportation system.
|
•
|
Delivery points. MIGC volumes can be redelivered to the hub in Glenrock, Wyoming, which has access to the following interstate pipelines:
|
◦
|
CIG pipeline;
|
◦
|
TIGT pipeline; and
|
◦
|
WIC pipeline.
|
•
|
Customers. For the year ended December 31, 2019, 8% of OTTCO’s throughput was from Occidental. The remaining throughput on the OTTCO transportation system was from two third-party shippers. Revenues on the OTTCO transportation system are generated from contracts that contain minimum-volume commitments and volumetric fees paid by shippers under firm and interruptible gas-transportation agreements.
|
•
|
Supply and delivery points. Supply points to the OTTCO transportation system include approximately 28 active wellheads, the Granger complex, and ExxonMobil Corporation’s Shute Creek plant, which are supplied by the eastern portion of the Greater Green River Basin, the Moxa Arch, and the Jonah and Pinedale Anticline fields. Primary delivery points include the Red Desert complex, two third-party industrial facilities, and an inactive interconnection with the Kern River pipeline.
|
•
|
Customers. For the year ended December 31, 2019, 93% of the Wamsutter pipeline throughput was from two third-party shippers, with the remaining throughput from Occidental. Revenues on the Wamsutter pipeline are generated from tariff-based rates regulated by the Wyoming Public Service Commission.
|
•
|
Supply and delivery points. The Wamsutter pipeline has two active receipt points in Sweetwater County, Wyoming, and delivers crude oil to MPLX LP’s SLC Core Pipeline System.
|
•
|
Front Range Pipeline. FRP provides NGLs takeaway capacity from the DJ Basin in Northeast Colorado. FRP has receipt points at gas plants in Weld and Adams Counties, Colorado (including the Lancaster and Wattenberg plants, which are within the DJ Basin complex) (see Rocky Mountains—Colorado and Utah within these Items 1 and 2). FRP connects to TEP near Skellytown, Texas. As of December 31, 2019, FRP had multiple committed shippers, including Occidental. FRP provides capacity to other shippers at the posted FERC tariff rate. In 2018, we elected to participate in the expansion of FRP, which is ongoing and expected to be completed in 2020. The expansion of FRP will increase its capacity by 100 MBbls/d, to a targeted total capacity of approximately 260 MBbls/d.
|
•
|
Texas Express Gathering. TEG consists of two NGLs gathering systems that provide plants in North Texas, the Texas panhandle, and West Oklahoma with access to NGLs takeaway capacity on TEP. TEG had one committed shipper as of December 31, 2019.
|
•
|
Texas Express Pipeline. TEP delivers to NGLs fractionation and storage facilities in Mont Belvieu, Texas. TEP is supplied with NGLs from other pipelines including FRP, the MAPL pipeline, and TEG. As of December 31, 2019, TEP had multiple committed shippers, including Occidental. TEP provides capacity to other shippers at the posted FERC tariff rates. In 2018, we elected to participate in the expansion of TEP. The expansion was completed in November 2019 and increased capacity by 90 MBbls/d, to a total capacity of approximately 350 MBbls/d.
|
•
|
Customers. As of December 31, 2019, the Cactus II pipeline had multiple committed shippers, including Occidental. The Cactus II pipeline also provides capacity to other shippers at the posted FERC-based rates.
|
•
|
Supply. The Cactus II pipeline is supplied by production from McCamey, Texas, and leases capacity on Plains All American Pipeline, L.P.’s intra-Delaware Basin pipelines to allow for origin points in Orla, Wink, Midland, and Crane, Texas.
|
•
|
Delivery points. The Cactus II pipeline transports crude oil from West Texas to the Corpus Christi, Texas, area. Primary delivery points in Corpus Christi include the Plains All American Pipeline; Nustar Energy, L.P.; Moda Ingleside Energy Center; and Buckeye Partners, L.P.’s export terminals.
|
•
|
Customers. As of December 31, 2019, the Red Bluff Express pipeline had multiple committed shippers, including Occidental. The Red Bluff Express pipeline also provides capacity to other shippers at the posted FERC-based rates.
|
•
|
Supply and delivery points. The Red Bluff Express pipeline is supplied by production from (i) our Ramsey and Mentone gas-processing plants that are part of the West Texas complex and (ii) other third-party plants. The Red Bluff Express pipeline transports natural gas from Reeves and Loving Counties, Texas, to the WAHA hub in Pecos County, Texas.
|
•
|
Latham Train II. As of December 31, 2019, we were constructing a second cryogenic train at the Latham processing plant at the DJ Basin complex. Latham Train II commenced operation in February 2020 with a capacity of 200 MMcf/d. Upon completion of Latham Train II, the DJ Basin complex has a total processing capacity of 1,680 MMcf/d.
|
•
|
Loving ROTF Trains III and IV. We currently are commissioning and constructing two additional oil-stabilization trains at the ROTFs (part of the DBM oil system). Loving ROTF Trains III and IV will have capacities of 30 MBbls/d each. Construction of Loving ROTF Train III was complete in the fourth quarter of 2019 and commenced operation in January 2020. Loving ROTF Train IV is expected to be completed in the fourth quarter of 2020. Upon completion, the DBM oil system will have a total processing capacity of 255 MBbls/d.
|
•
|
rates, services, and terms and conditions of service;
|
•
|
types of services that may be offered to customers;
|
•
|
certification and construction of new facilities;
|
•
|
acquisition, extension, disposition, or abandonment of facilities;
|
•
|
maintenance of accounts and records;
|
•
|
internet posting requirements for available capacity, discounts, and other matters;
|
•
|
pipeline segmentation to allow multiple simultaneous shipments under the same contract;
|
•
|
capacity release to create a secondary market for transportation services;
|
•
|
relationships between affiliated companies involved in certain aspects of the natural-gas business;
|
•
|
initiation and discontinuation of services;
|
•
|
market manipulation in connection with interstate sales, purchases, or transportation of natural gas and NGLs; and
|
•
|
participation by interstate pipelines in cash management arrangements.
|
•
|
the Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, operational, monitoring, and reporting requirements, and that the U.S. Environmental Protection Agency (the “EPA”) has relied on as the authority for adopting climate-change regulatory initiatives relating to greenhouse gas (“GHG”) emissions;
|
•
|
the Federal Water Pollution Control Act, also known as the Clean Water Act, which regulates discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;
|
•
|
the Oil Pollution Act of 1990, which subjects, among others, owners and operators of onshore facilities and pipelines to liability for removal costs and damages arising from an oil spill in waters of the United States;
|
•
|
regulations imposed by the Bureau of Land Management (the “BLM”) and the Bureau of Indian Affairs, agencies under the authority of the U.S. Department of the Interior, which govern and restrict aspects of oil and natural-gas operations on federal and Native American lands, including the imposition of liabilities for pollution damages and pollution clean-up costs resulting from such operations;
|
•
|
the Comprehensive Environmental Response, Compensation and Liability Act of 1980, which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;
|
•
|
the Resource Conservation and Recovery Act, which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;
|
•
|
the Safe Drinking Water Act, which regulates the quality of the nation’s public drinking water through adoption of drinking-water standards and control over the injection of waste fluids into non-producing geologic formations that may adversely affect drinking water sources;
|
•
|
the Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety-hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories;
|
•
|
OSHA, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;
|
•
|
the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;
|
•
|
the National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment; and
|
•
|
U.S. Department of Transportation regulations, which relate to advancing the safe transportation of energy and hazardous materials and emergency response preparedness.
|
•
|
our ability to pay distributions to our unitholders;
|
•
|
our assumptions about the energy market;
|
•
|
future throughput (including Occidental production) that 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 financing through the debt or equity capital markets;
|
•
|
the supply of, demand for, and price of, oil, natural gas, NGLs, and related products or services;
|
•
|
commodity-price risks inherent in percent-of-proceeds, percent-of-product, and keep-whole contracts;
|
•
|
weather and natural disasters;
|
•
|
inflation;
|
•
|
the availability of goods and services;
|
•
|
general economic conditions, internationally, domestically, or in the jurisdictions in which we are doing business;
|
•
|
federal, state, and local laws and state-approved voter ballot initiatives, including those laws or ballot initiatives that limit producers’ hydraulic-fracturing activities or other oil and natural-gas development or 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 Occidental;
|
•
|
the creditworthiness of Occidental or our other counterparties, including financial institutions, operating partners, and other parties;
|
•
|
changes in Occidental’s capital program, corporate strategy, or other desired areas of focus;
|
•
|
our commitments to capital projects;
|
•
|
our ability to access liquidity under the RCF;
|
•
|
our ability to repay debt;
|
•
|
conflicts of interest among us, our general partner and its affiliates, including Occidental, with respect to, among other things, the allocation of capital and operational and administrative costs, and our future business opportunities;
|
•
|
our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;
|
•
|
our ability to acquire assets on acceptable terms from third parties;
|
•
|
non-payment or non-performance of significant customers, including under gathering, processing, transportation, and disposal agreements and the $260.0 million note receivable from Anadarko;
|
•
|
the timing, amount, and terms of future issuances of equity and debt securities;
|
•
|
the outcome of pending and future regulatory, legislative, or other proceedings or investigations, and continued or additional disruptions in operations that may occur as we and our customers comply with any regulatory orders or other state or local changes in laws or regulations; and
|
•
|
other factors discussed below and elsewhere in this Item 1A, under the caption Critical Accounting Estimates included under Part II, Item 7 of this Form 10-K, and in our other public filings and press releases.
|
•
|
the volatility of oil and natural-gas prices, which could have a negative effect on the value of Occidental’s oil and natural-gas properties, its drilling programs, and its ability to finance its operations;
|
•
|
the availability of capital on favorable terms to fund Occidental’s exploration and development activities;
|
•
|
a reduction in or reallocation of Occidental’s capital budget, which could reduce the gathering, transportation, and treating volumes available to us as a midstream operator, and/or limit our opportunities for organic growth;
|
•
|
Occidental’s ability to replace its oil and natural-gas reserves;
|
•
|
Occidental’s operations in foreign countries, which are subject to political, economic, and other uncertainties;
|
•
|
Occidental’s drilling, flowline, pipeline, and operating risks, including potential environmental liabilities;
|
•
|
transportation-capacity constraints and interruptions;
|
•
|
adverse effects of governmental and environmental regulation, including state-approved ballot initiatives that would change state constitutions or statutes in a manner that makes future oil and gas development in such states more difficult or expensive;
|
•
|
shareholder activism with respect to Occidental’s stock or activities by non-governmental organizations to restrict the exploration, development, and production of oil and natural gas by Occidental; and
|
•
|
adverse effects from current or future litigation.
|
•
|
implementing technology systems to manage the operations and administration of our day-to-day business;
|
•
|
maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002;
|
•
|
replicating regulatory compliance and governance infrastructure:
|
•
|
hiring, training, or retaining qualified personnel as needed to replace positions that have previously been provided as a shared service by Occidental;
|
•
|
identifying and filling gaps in management functions and expertise and establishing effective communication and information exchange among management teams and employees;
|
•
|
diverting management’s attention from our existing business; and
|
•
|
potentially losing business or key employees.
|
•
|
domestic and worldwide economic and geopolitical conditions;
|
•
|
weather conditions and seasonal trends;
|
•
|
the ability to develop recently discovered fields or deploy new technologies to existing fields;
|
•
|
the levels of domestic production and consumer demand, as affected by, among other things, concerns over inflation, geopolitical issues, and the availability and cost of credit;
|
•
|
the availability of imported, or a market for exported, liquefied natural gas;
|
•
|
the availability of transportation systems with adequate capacity;
|
•
|
the volatility and uncertainty of regional pricing differentials, such as in the Rocky Mountains;
|
•
|
the price and availability of alternative fuels;
|
•
|
the effect of energy conservation measures;
|
•
|
the nature and extent of governmental regulation and taxation; and
|
•
|
the forecasted supply and demand for, and prices of, oil, natural gas, NGLs, and other commodities.
|
•
|
the prices of, level of production of, and demand for oil and natural gas;
|
•
|
the volume of oil, NGLs, natural gas, and produced water we gather, compress, process, treat, dispose, and/or transport;
|
•
|
the volumes and prices of NGLs and condensate that we retain and sell;
|
•
|
demand charges and volumetric fees associated with our transportation services;
|
•
|
the level of competition from other midstream companies;
|
•
|
regulatory action affecting the supply of or demand for oil or natural gas, the rates we can charge, how we contract for services, our existing contracts, our operating costs, or our operating flexibility; and
|
•
|
prevailing economic conditions.
|
•
|
our level of capital expenditures;
|
•
|
our level of operating and maintenance and general and administrative costs;
|
•
|
our debt-service requirements and other liabilities;
|
•
|
fluctuations in our working capital needs;
|
•
|
our ability to borrow funds and access capital markets;
|
•
|
our continued 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 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 financing may not be available on favorable terms;
|
•
|
our funds available for operations, future business opportunities, and distributions to unitholders will be reduced by that portion of our cash flows required to make interest payments on our debt;
|
•
|
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
|
•
|
our flexibility in responding to changing business and economic conditions may be limited.
|
•
|
Ground-Level Ozone Standards. In 2015, the EPA issued a rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion under the primary and secondary standards to provide requisite protection of public health and welfare, respectively. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either “attainment/unclassifiable,” “unclassifiable,” or “non-attainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs.
|
•
|
Reduction of Methane Emissions by the Oil and Gas Industry. In 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed oil and natural-gas production and natural-gas processing and transmission facilities. The EPA’s rule is comprised of New Source Performance Standards (“NSPS”), known as Subpart OOOOa, which require certain new, modified, or reconstructed facilities in the oil and natural-gas sector to reduce methane gas and volatile organic compound emissions. These Subpart OOOOa standards expand previously issued NSPS to, among other things, hydraulically fractured oil and natural-gas well completions, fugitive emissions from well sites and compressors, and equipment leaks at natural-gas processing plants and pneumatic pumps. In February 2018, the EPA finalized amendments to certain requirements of the 2016 final rule and, in September 2018, the agency proposed amendments that included rescission or revision of specified rule requirements, such as fugitive emission monitoring frequency. In August 2019, the EPA proposed two options for rescinding the Subpart OOOOa standards. Under the EPA’s preferred alternative, the agency would rescind the methane limits for new, reconstructed, and modified oil and natural-gas production sources while leaving in place the general emission limits for volatile organic compounds (“VOCs”) and relieve the EPA of its obligation to develop guidelines for methane emissions from existing sources. In addition, the proposal would remove from the oil and natural-gas category the natural-gas transmission and storage segment. The other proposed alternative would rescind the methane requirements of the NSPS applicable to all oil and natural-gas sources, without removing any sources from that category (and still requiring control of VOCs in general). In a separate rulemaking, the BLM published a final rule in late 2016 that requires a reduction in methane emissions by regulating venting, flaring, and leaking from oil and natural-gas operations on public lands; however, in September 2018, the BLM published a final rule rescinding most of the new requirements of the 2016 final rule and codifying the BLM’s prior approach to venting and flaring, which rescission has been challenged in federal court and remains pending. Notwithstanding the uncertainty of the 2016 rule, we have taken measures to enter into a voluntary regime, together with certain other oil and natural-gas exploration and production operators, to reduce methane emissions. At the state level, some states where we conduct operations, including Colorado, have issued requirements for the performance of leak detection programs that identify and repair methane leaks at certain oil and natural-gas sources. Compliance with these rules or with any future federal or state methane regulations could, among other things, require installation of new emission controls on some of our equipment and increase our capital expenditures and operating costs.
|
•
|
Reduction of GHG Emissions. The U.S. Congress and the EPA, in addition to some state and regional authorities, have in recent years considered legislation or regulations to reduce emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG-reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislation, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the Clean Air Act and may require the installation of “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs together with other criteria pollutants. Also, certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of GHG emissions from specified onshore and offshore production sources. Additionally, in April 2016, the United States joined other countries in entering into a United Nations-sponsored non-binding agreement negotiated in Paris, France (“Paris Agreement”) for nations to limit their GHG emissions through individually determined reduction goals every five years beginning in 2020. However, in August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement, and in November 2019 the United States formally initiated the withdrawal process. The implementation of substantial limitations on GHG emissions in areas where we conduct operations could result in increased compliance costs to acquire emissions allowances or comply with new regulatory or reporting requirements, which developments could adversely affect demand for oil and natural gas that our customers produce, reduce demand for our services, and have a material adverse effect on our business, financial condition, and results of operation.
|
•
|
damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, and other natural disasters, and acts of terrorism;
|
•
|
inadvertent damage from construction, farm, and utility equipment;
|
•
|
leaks or losses of hydrocarbons or produced water as a result of the malfunction of equipment or facilities;
|
•
|
fires and explosions (for example, see Items Affecting the Comparability of Our Financial Results, under Part II, Item 7 of this Form 10-K for a discussion of the incident at the DBM complex); and
|
•
|
other hazards that could also result in personal injury, loss of life, pollution, property or natural resource damages, and/or curtailment or suspension of operations.
|
•
|
mistaken assumptions about volumes or the timing of the delivery of volumes, revenues or costs, including synergies;
|
•
|
an inability to successfully integrate the acquired assets or businesses;
|
•
|
the assumption of unknown liabilities, including environmental 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 to other business concerns;
|
•
|
unforeseen difficulties operating in new geographic areas; and
|
•
|
customer or key employee losses at the acquired businesses.
|
•
|
Neither our partnership agreement nor any other agreement requires Occidental to pursue a business strategy that favors us.
|
•
|
Occidental 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 Occidental, in resolving conflicts of interest.
|
•
|
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 may cause us to borrow funds in order to permit the payment of cash distributions.
|
•
|
Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
|
•
|
Our general partner has limited, and intends to continue to limit, its liability regarding our contractual and other obligations.
|
•
|
Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.
|
•
|
how to allocate corporate opportunities among us and its affiliates;
|
•
|
how to exercise voting rights with respect to the units it owns;
|
•
|
whether to exercise its registration rights; and
|
•
|
whether to consent to any merger or consolidation of the Partnership or amendment to the partnership agreement.
|
•
|
provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
|
•
|
provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in the best interest of the Partnership;
|
•
|
provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
|
•
|
provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is any of the following:
|
(a)
|
approved by the Special Committee of the Board of Directors, although our general partner is not obligated to seek such approval;
|
(b)
|
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
|
(c)
|
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
|
(d)
|
fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
|
•
|
our existing unitholders’ proportionate ownership interest in us will decrease;
|
•
|
the amount of per-unit cash available for distribution 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 Occidental’s and our financial performance or our future distribution growth;
|
•
|
the public’s reaction to Occidental’s or our press releases, announcements, and filings with the SEC;
|
•
|
legislative or regulatory changes affecting our status as a partnership for federal income tax purposes;
|
•
|
fluctuations in broader securities market prices and volumes, particularly among securities of midstream companies and securities of publicly traded limited partnerships;
|
•
|
changes in market valuations of similar companies;
|
•
|
departures of key personnel;
|
•
|
commencement of or involvement in litigation;
|
•
|
variations in our quarterly results of operations or those of other midstream companies;
|
•
|
variations in the amount of our quarterly cash distributions;
|
•
|
future issuances and sales of our common units; and
|
•
|
changes in general conditions in the U.S. economy, financial markets, or the midstream industry.
|
|
|
Acquisition Date
|
|
Percentage Acquired
|
|
Affiliate or Third-party Acquisition
|
|
DBJV system
|
|
03/02/2015
|
|
50
|
%
|
|
Affiliate
|
Springfield system
|
|
03/14/2016
|
|
50.1
|
%
|
|
Affiliate
|
DBJV system (1)
|
|
03/17/2017
|
|
50
|
%
|
|
Third party
|
Whitethorn LLC (2)
|
|
06/01/2018
|
|
20
|
%
|
|
Third party
|
Cactus II (2)
|
|
06/27/2018
|
|
15
|
%
|
|
Third party
|
Red Bluff Express (2)
|
|
01/18/2019
|
|
30
|
%
|
|
Third party
|
(1)
|
See Property exchange below.
|
(2)
|
See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional details.
|
|
|
Summary Financial Information
|
||||||||||||||||||
thousands except per-unit data, throughput, per-Mcf Adjusted gross margin, and per-Bbl Adjusted gross margin
|
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
Statement of Operations Data (for the year ended):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues and other
|
|
$
|
2,746,174
|
|
|
$
|
2,299,658
|
|
|
$
|
2,429,614
|
|
|
$
|
1,941,330
|
|
|
$
|
1,853,233
|
|
Cost of product
|
|
444,247
|
|
|
415,505
|
|
|
953,792
|
|
|
517,371
|
|
|
551,287
|
|
|||||
Operating income (loss)
|
|
1,231,343
|
|
|
861,282
|
|
|
801,698
|
|
|
783,082
|
|
|
202,105
|
|
|||||
Net income (loss)
|
|
807,700
|
|
|
630,654
|
|
|
737,385
|
|
|
658,286
|
|
|
48,980
|
|
|||||
Net income (loss) attributable to noncontrolling interests
|
|
110,459
|
|
|
79,083
|
|
|
196,595
|
|
|
251,208
|
|
|
(154,409
|
)
|
|||||
Net income (loss) attributable to Western Midstream Partners, LP
|
|
697,241
|
|
|
551,571
|
|
|
540,790
|
|
|
407,078
|
|
|
203,389
|
|
|||||
Net income (loss) per common unit – basic and diluted
|
|
1.59
|
|
|
1.69
|
|
|
1.72
|
|
|
1.53
|
|
|
0.39
|
|
|||||
Distributions per unit
|
|
2.47000
|
|
|
2.34875
|
|
|
2.10500
|
|
|
1.76750
|
|
|
1.49125
|
|
|||||
Balance Sheet Data (at year end):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
|
$
|
12,346,453
|
|
|
$
|
11,457,205
|
|
|
$
|
9,430,090
|
|
|
$
|
8,709,610
|
|
|
$
|
8,196,163
|
|
Total long-term liabilities
|
|
8,515,206
|
|
|
5,927,045
|
|
|
3,887,074
|
|
|
3,503,934
|
|
|
3,285,264
|
|
|||||
Total equity and partners’ capital
|
|
3,345,293
|
|
|
4,892,683
|
|
|
4,995,050
|
|
|
4,872,656
|
|
|
4,645,456
|
|
|||||
Cash Flow Data (for the year ended):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash flows provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
|
$
|
1,324,100
|
|
|
$
|
1,348,175
|
|
|
$
|
1,042,715
|
|
|
$
|
1,056,149
|
|
|
$
|
873,330
|
|
Investing activities
|
|
(3,387,853
|
)
|
|
(2,210,813
|
)
|
|
(1,133,324
|
)
|
|
(1,229,874
|
)
|
|
(740,816
|
)
|
|||||
Financing activities
|
|
2,071,573
|
|
|
875,192
|
|
|
(188,875
|
)
|
|
433,103
|
|
|
(100,033
|
)
|
|||||
Capital expenditures
|
|
(1,188,829
|
)
|
|
(1,948,595
|
)
|
|
(1,026,932
|
)
|
|
(547,986
|
)
|
|
(786,945
|
)
|
|||||
Throughput for natural-gas assets (MMcf/d):
|
||||||||||||||||||||
Total throughput
|
|
4,423
|
|
|
4,068
|
|
|
3,840
|
|
|
4,219
|
|
|
4,442
|
|
|||||
Throughput attributable to noncontrolling interests (1)
|
|
175
|
|
|
170
|
|
|
179
|
|
|
206
|
|
|
228
|
|
|||||
Total throughput attributable to WES for natural-gas assets
|
|
4,248
|
|
|
3,898
|
|
|
3,661
|
|
|
4,013
|
|
|
4,214
|
|
|||||
Throughput for crude-oil, NGLs, and produced-water assets (MBbls/d)
|
||||||||||||||||||||
Total throughput
|
|
1,219
|
|
|
775
|
|
|
406
|
|
|
371
|
|
|
295
|
|
|||||
Throughput attributable to noncontrolling interests (1)
|
|
24
|
|
|
15
|
|
|
8
|
|
|
7
|
|
|
6
|
|
|||||
Total throughput attributable to WES for crude-oil, NGLs, and produced-water assets
|
|
1,195
|
|
|
760
|
|
|
398
|
|
|
364
|
|
|
289
|
|
|||||
Key Performance Metrics (for the year ended): (2)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Adjusted gross margin for natural-gas assets
|
|
$
|
1,656,041
|
|
|
$
|
1,443,466
|
|
|
$
|
1,256,160
|
|
|
$
|
1,225,245
|
|
|
$
|
1,168,141
|
|
Adjusted gross margin for crude-oil, NGLs, and produced-water assets
|
|
772,036
|
|
|
534,739
|
|
|
263,709
|
|
|
227,679
|
|
|
159,116
|
|
|||||
Per-Mcf Adjusted gross margin for natural-gas assets
|
|
1.07
|
|
|
1.01
|
|
|
0.94
|
|
|
0.83
|
|
|
0.76
|
|
|||||
Per-Bbl Adjusted gross margin for crude-oil, NGLs, and produced-water assets
|
|
1.77
|
|
|
1.93
|
|
|
1.82
|
|
|
1.71
|
|
|
1.51
|
|
|||||
Adjusted EBITDA
|
|
1,719,090
|
|
|
1,466,445
|
|
|
1,169,651
|
|
|
1,114,114
|
|
|
961,139
|
|
|||||
Distributable cash flow
|
|
1,325,445
|
|
|
1,139,587
|
|
|
1,010,850
|
|
|
923,163
|
|
|
830,017
|
|
(1)
|
For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
(2)
|
Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow are not defined in GAAP. For definitions and reconciliations of these non-GAAP financial measures to their most directly comparable financial measure calculated and presented in accordance with GAAP, see How We Evaluate Our Operations under Part II, Item 7 of this Form 10-K.
|
|
|
Summary Financial Information
|
||||||||||||||||||
thousands except per-unit data
|
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
Statement of Operations Data (for the year ended):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues and other
|
|
$
|
2,746,174
|
|
|
$
|
2,299,658
|
|
|
$
|
2,429,614
|
|
|
$
|
1,941,330
|
|
|
$
|
1,853,233
|
|
Cost of product
|
|
444,247
|
|
|
415,505
|
|
|
953,792
|
|
|
517,371
|
|
|
551,287
|
|
|||||
Operating income (loss)
|
|
1,238,162
|
|
|
865,311
|
|
|
804,570
|
|
|
786,755
|
|
|
205,253
|
|
|||||
Net income (loss)
|
|
814,685
|
|
|
636,526
|
|
|
742,401
|
|
|
663,600
|
|
|
52,089
|
|
|||||
Net income (loss) attributable to noncontrolling interest
|
|
7,095
|
|
|
8,609
|
|
|
10,735
|
|
|
10,963
|
|
|
10,101
|
|
|||||
Net income (loss) attributable to Western Midstream Operating, LP
|
|
807,590
|
|
|
627,917
|
|
|
731,666
|
|
|
652,637
|
|
|
41,988
|
|
|||||
Net income (loss) per common unit – basic and diluted
|
|
N/A
|
|
|
0.55
|
|
|
1.30
|
|
|
1.74
|
|
|
(1.95
|
)
|
|||||
Distributions per unit
|
|
—
|
|
|
3.830
|
|
|
3.590
|
|
|
3.350
|
|
|
3.050
|
|
|||||
Balance Sheet Data (at year end):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
|
$
|
12,342,825
|
|
|
$
|
11,454,845
|
|
|
$
|
9,428,129
|
|
|
$
|
8,706,541
|
|
|
$
|
8,194,016
|
|
Total long-term liabilities
|
|
8,515,206
|
|
|
5,927,045
|
|
|
3,859,074
|
|
|
3,475,934
|
|
|
3,285,264
|
|
|||||
Total equity and partners’ capital
|
|
3,341,819
|
|
|
4,919,597
|
|
|
5,021,182
|
|
|
4,897,669
|
|
|
4,643,386
|
|
|||||
Cash Flow Data (for the year ended):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash flows provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
|
$
|
1,332,189
|
|
|
$
|
1,352,114
|
|
|
$
|
1,046,798
|
|
|
$
|
1,060,658
|
|
|
$
|
876,166
|
|
Investing activities
|
|
(3,387,853
|
)
|
|
(2,210,813
|
)
|
|
(1,133,324
|
)
|
|
(1,229,874
|
)
|
|
(740,816
|
)
|
|||||
Financing activities
|
|
2,063,338
|
|
|
870,333
|
|
|
(192,585
|
)
|
|
429,108
|
|
|
(104,371
|
)
|
|||||
Capital expenditures
|
|
(1,188,829
|
)
|
|
(1,948,595
|
)
|
|
(1,026,932
|
)
|
|
(547,986
|
)
|
|
(786,945
|
)
|
|
|
Wholly
Owned and
Operated
|
|
Operated
Interests
|
|
Non-Operated
Interests
|
|
Equity
Interests
|
||||
Gathering systems (1)
|
|
17
|
|
|
2
|
|
|
3
|
|
|
2
|
|
Treating facilities
|
|
37
|
|
|
3
|
|
|
—
|
|
|
3
|
|
Natural-gas processing plants/trains
|
|
25
|
|
|
3
|
|
|
—
|
|
|
5
|
|
NGLs pipelines
|
|
2
|
|
|
—
|
|
|
—
|
|
|
4
|
|
Natural-gas pipelines
|
|
5
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Crude-oil pipelines
|
|
3
|
|
|
1
|
|
|
—
|
|
|
3
|
|
(1)
|
Includes the DBM water systems.
|
•
|
Exchange Agreement. WGRI, the general partner, and WES entered into a partnership interests exchange agreement (the “Exchange Agreement”), pursuant to which WES canceled the non-economic general partner interest in WES and simultaneously issued a 2.0% general partner interest to the general partner in exchange for which WGRI transferred 9,060,641 WES common units to WES, which immediately canceled such units on receipt.
|
•
|
Services, Secondment, and Employee Transfer Agreement. Occidental, Anadarko, and WES Operating GP entered into the Services Agreement, pursuant to which Occidental, Anadarko, and their subsidiaries will (i) second certain personnel employed by Occidental to WES Operating GP, in exchange for which WES Operating GP will pay a monthly secondment and shared services fee to Occidental equivalent to the direct cost of the seconded employees and (ii) continue to provide certain administrative and operational services to WES for up to a two-year transition period. The Services Agreement also includes provisions governing the transfer of certain employees to WES and WES’s assumption of liabilities relating to those employees at the time of their transfer. In January 2020, pursuant to the Services Agreement, Occidental made a one-time cash contribution of $20.0 million to WES for anticipated transition costs required to establish stand-alone human resources and information technology functions.
|
•
|
RCF amendment. WES Operating entered into an amendment to its RCF to, among other things, (i) effective on February 14, 2020, exercise the final one-year extension option to extend the maturity date of the RCF to February 14, 2025, for the extending lenders, and (ii) modify the change of control definition to provide, among other things, that, subject to certain conditions, if the limited partners of WES elect to remove the general partner as the general partner of WES in accordance with the terms of the partnership agreement, then such removal will not constitute a change of control under the RCF.
|
•
|
Term loan facility amendment. WES Operating entered into an amendment of its Term loan facility to, among other things, modify the change of control definition to provide, among other things, that, subject to certain conditions, if the limited partners of WES elect to remove the general partner as the general partner of WES in accordance with the terms of the partnership agreement, then such removal will not constitute a change of control under the Term loan facility.
|
•
|
Termination of debt-indemnification agreements. WES Operating GP and certain wholly owned subsidiaries of Occidental mutually terminated the debt-indemnification agreements related to indebtedness incurred by WES Operating.
|
•
|
Termination of omnibus agreements. WES and WES Operating entered into agreements with Occidental to terminate the WES and WES Operating omnibus agreements. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information on the WES and WES Operating omnibus agreements.
|
•
|
We increased our per-unit distribution to $0.62200 for the fourth quarter of 2019, representing a 0.3% increase over the third-quarter 2019 distribution and a 3% increase over the fourth-quarter 2018 distribution.
|
•
|
In July 2019, WES Operating entered into an amendment to the Term loan facility to (i) extend the maturity date from February 2020 to December 2020, and (ii) increase commitments available under the Term loan facility from $2.0 billion to $3.0 billion, the incremental $1.0 billion of which was subsequently drawn by WES Operating on September 13, 2019, and used to repay outstanding borrowings under the RCF. In December 2019, WES Operating amended certain provisions of the Term loan facility. See Liquidity and Capital Resources within this Item 7 for additional information.
|
•
|
In March 2019, WES Operating entered into additional interest-rate swap agreements with an aggregate notional principal amount of $375.0 million. In November and December 2019, WES Operating entered into additional interest-rate swap agreements with an aggregate notional principal amount of $1,125.0 million, effectively offsetting those entered into in December 2018 and March 2019. In December 2019, all outstanding interest-rate swap agreements were cash-settled. See Liquidity and Capital Resources within this Item 7 for additional information.
|
•
|
In March 2019, the WGP RCF matured and the outstanding borrowings were repaid. See Liquidity and Capital Resources within this Item 7 for additional information.
|
•
|
We commenced operations of Mentone Train II at the West Texas complex (with capacity of 200 MMcf/d) and Latham Train I at the DJ Basin complex (with capacity of 200 MMcf/d) at the end of the first and fourth quarters, respectively, of 2019.
|
•
|
In February 2019, WES Operating increased the size of the RCF from $1.5 billion to $2.0 billion and extended the maturity date of the RCF to February 2024. In December 2019, WES Operating extended the maturity date of the RCF to February 2025 for the extending lenders and modified the change of control definition in the RCF. See Liquidity and Capital Resources within this Item 7 for additional information.
|
•
|
In January 2019, we acquired a 30% interest in Red Bluff Express from a third party. See Acquisitions and Divestitures under Part I, Items 1 and 2 of this Form 10-K for additional information.
|
•
|
Natural-gas throughput attributable to WES totaled 4,248 MMcf/d for the year ended December 31, 2019, representing a 9% increase compared to the year ended December 31, 2018.
|
•
|
Crude-oil, NGLs, and produced-water throughput attributable to WES totaled 1,195 MBbls/d for the year ended December 31, 2019, representing a 57% increase compared to the year ended December 31, 2018.
|
•
|
Operating income (loss) was $1,231.3 million for the year ended December 31, 2019, representing a 43% increase compared to the year ended December 31, 2018.
|
•
|
Adjusted gross margin for natural-gas assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $1.07 per Mcf for the year ended December 31, 2019, representing a 6% increase compared to the year ended December 31, 2018.
|
•
|
Adjusted gross margin for crude-oil, NGLs, and produced-water assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $1.77 per Bbl for the year ended December 31, 2019, representing an 8% decrease compared to the year ended December 31, 2018.
|
|
|
Year Ended December 31,
|
|||||||||||||||||||||||||
|
|
2019
|
|
2018
|
|
Inc/
(Dec) |
|
2019
|
|
2018
|
|
Inc/
(Dec) |
|
2019
|
|
2018
|
|
Inc/
(Dec) |
|||||||||
|
|
Natural gas
(MMcf/d)
|
|
Crude oil & NGLs
(MBbls/d)
|
|
Produced water
(MBbls/d)
|
|||||||||||||||||||||
Delaware Basin
|
|
1,226
|
|
|
1,041
|
|
|
18
|
%
|
|
150
|
|
|
132
|
|
|
14
|
%
|
|
556
|
|
|
239
|
|
|
133
|
%
|
DJ Basin
|
|
1,236
|
|
|
1,133
|
|
|
9
|
%
|
|
118
|
|
|
105
|
|
|
12
|
%
|
|
—
|
|
|
—
|
|
|
—
|
%
|
Equity investments
|
|
398
|
|
|
291
|
|
|
37
|
%
|
|
343
|
|
|
241
|
|
|
42
|
%
|
|
—
|
|
|
—
|
|
|
—
|
%
|
Other
|
|
1,563
|
|
|
1,603
|
|
|
(2
|
)%
|
|
52
|
|
|
58
|
|
|
(10
|
)%
|
|
—
|
|
|
—
|
|
|
—
|
%
|
Total throughput
|
|
4,423
|
|
|
4,068
|
|
|
9
|
%
|
|
663
|
|
|
536
|
|
|
24
|
%
|
|
556
|
|
|
239
|
|
|
133
|
%
|
•
|
expenses associated with annual and quarterly reporting;
|
•
|
tax return and Schedule K-1 preparation and distribution expenses;
|
•
|
expenses associated with listing on the NYSE; and
|
•
|
independent auditor fees, legal expenses, investor relations expenses, director fees, and registrar and transfer agent fees.
|
•
|
our operating performance as compared to other publicly traded partnerships in the midstream industry, without regard to financing methods, capital structure, or historical cost basis;
|
•
|
the ability of our assets to generate cash flow to make distributions; and
|
•
|
the viability of acquisitions and capital expenditures and the returns on investment of various investment opportunities.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
Reconciliation of Operating income (loss) to Adjusted gross margin
|
|
|
|
|
|
|
||||||
Operating income (loss)
|
|
$
|
1,231,343
|
|
|
$
|
861,282
|
|
|
$
|
801,698
|
|
Add:
|
|
|
|
|
|
|
||||||
Distributions from equity investments
|
|
264,828
|
|
|
216,977
|
|
|
148,752
|
|
|||
Operation and maintenance
|
|
641,219
|
|
|
480,861
|
|
|
345,617
|
|
|||
General and administrative
|
|
114,591
|
|
|
67,195
|
|
|
53,949
|
|
|||
Property and other taxes
|
|
61,352
|
|
|
51,848
|
|
|
53,147
|
|
|||
Depreciation and amortization
|
|
483,255
|
|
|
389,164
|
|
|
318,771
|
|
|||
Impairments
|
|
6,279
|
|
|
230,584
|
|
|
180,051
|
|
|||
Less:
|
|
|
|
|
|
|
||||||
Gain (loss) on divestiture and other, net
|
|
(1,406
|
)
|
|
1,312
|
|
|
132,388
|
|
|||
Proceeds from business interruption insurance claims
|
|
—
|
|
|
—
|
|
|
29,882
|
|
|||
Equity income, net – affiliates
|
|
237,518
|
|
|
195,469
|
|
|
115,141
|
|
|||
Reimbursed electricity-related charges recorded as revenues
|
|
74,629
|
|
|
66,678
|
|
|
56,860
|
|
|||
Adjusted gross margin attributable to noncontrolling interests (1)
|
|
64,049
|
|
|
56,247
|
|
|
47,845
|
|
|||
Adjusted gross margin
|
|
$
|
2,428,077
|
|
|
$
|
1,978,205
|
|
|
$
|
1,519,869
|
|
Adjusted gross margin for natural-gas assets
|
|
$
|
1,656,041
|
|
|
$
|
1,443,466
|
|
|
$
|
1,256,160
|
|
Adjusted gross margin for crude-oil, NGLs, and produced-water assets
|
|
772,036
|
|
|
534,739
|
|
|
263,709
|
|
(1)
|
For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
Reconciliation of Net income (loss) to Adjusted EBITDA
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
807,700
|
|
|
$
|
630,654
|
|
|
$
|
737,385
|
|
Add:
|
|
|
|
|
|
|
||||||
Distributions from equity investments
|
|
264,828
|
|
|
216,977
|
|
|
148,752
|
|
|||
Non-cash equity-based compensation expense
|
|
14,392
|
|
|
7,310
|
|
|
5,194
|
|
|||
Interest expense
|
|
303,286
|
|
|
183,831
|
|
|
142,520
|
|
|||
Income tax expense
|
|
13,472
|
|
|
58,934
|
|
|
20,483
|
|
|||
Depreciation and amortization
|
|
483,255
|
|
|
389,164
|
|
|
318,771
|
|
|||
Impairments
|
|
6,279
|
|
|
230,584
|
|
|
180,051
|
|
|||
Other expense
|
|
161,813
|
|
|
8,264
|
|
|
145
|
|
|||
Less:
|
|
|
|
|
|
|
||||||
Gain (loss) on divestiture and other, net
|
|
(1,406
|
)
|
|
1,312
|
|
|
132,388
|
|
|||
Equity income, net – affiliates
|
|
237,518
|
|
|
195,469
|
|
|
115,141
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Other income
|
|
37,792
|
|
|
2,749
|
|
|
1,384
|
|
|||
Income tax benefit
|
|
—
|
|
|
—
|
|
|
80,406
|
|
|||
Adjusted EBITDA attributable to noncontrolling interests (1)
|
|
45,131
|
|
|
42,843
|
|
|
37,431
|
|
|||
Adjusted EBITDA
|
|
$
|
1,719,090
|
|
|
$
|
1,466,445
|
|
|
$
|
1,169,651
|
|
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
|
$
|
1,324,100
|
|
|
$
|
1,348,175
|
|
|
$
|
1,042,715
|
|
Interest (income) expense, net
|
|
286,386
|
|
|
166,931
|
|
|
125,620
|
|
|||
Uncontributed cash-based compensation awards
|
|
(1,102
|
)
|
|
879
|
|
|
25
|
|
|||
Accretion and amortization of long-term obligations, net
|
|
(8,441
|
)
|
|
(5,943
|
)
|
|
(4,932
|
)
|
|||
Current income tax (benefit) expense
|
|
5,863
|
|
|
(80,114
|
)
|
|
(6,785
|
)
|
|||
Other (income) expense, net (2)
|
|
106,136
|
|
|
(3,209
|
)
|
|
(1,384
|
)
|
|||
Distributions from equity investments in excess of cumulative earnings – affiliates
|
|
30,256
|
|
|
29,585
|
|
|
31,659
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
|
||||||
Accounts receivable, net
|
|
45,033
|
|
|
60,502
|
|
|
16,244
|
|
|||
Accounts and imbalance payables and accrued liabilities, net
|
|
30,866
|
|
|
(45,605
|
)
|
|
937
|
|
|||
Other items, net
|
|
(54,876
|
)
|
|
38,087
|
|
|
2,983
|
|
|||
Adjusted EBITDA attributable to noncontrolling interests (1)
|
|
(45,131
|
)
|
|
(42,843
|
)
|
|
(37,431
|
)
|
|||
Adjusted EBITDA
|
|
$
|
1,719,090
|
|
|
$
|
1,466,445
|
|
|
$
|
1,169,651
|
|
Cash flow information
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
|
$
|
1,324,100
|
|
|
$
|
1,348,175
|
|
|
$
|
1,042,715
|
|
Net cash used in investing activities
|
|
(3,387,853
|
)
|
|
(2,210,813
|
)
|
|
(1,133,324
|
)
|
|||
Net cash provided by (used in) financing activities
|
|
2,071,573
|
|
|
875,192
|
|
|
(188,875
|
)
|
(1)
|
For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
(2)
|
Excludes net non-cash losses on interest-rate swaps of $25.6 million and $8.0 million for the years ended December 31, 2019 and 2018, respectively. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
|
|
Year Ended December 31,
|
||||||||||
thousands except Coverage ratio
|
|
2019
|
|
2018
|
|
2017
|
||||||
Reconciliation of Net income (loss) to Distributable cash flow and calculation of the Coverage ratio
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
807,700
|
|
|
$
|
630,654
|
|
|
$
|
737,385
|
|
Add:
|
|
|
|
|
|
|
||||||
Distributions from equity investments
|
|
264,828
|
|
|
216,977
|
|
|
148,752
|
|
|||
Non-cash equity-based compensation expense
|
|
14,392
|
|
|
7,310
|
|
|
5,194
|
|
|||
Non-cash settled interest expense, net
|
|
39
|
|
|
—
|
|
|
71
|
|
|||
Income tax (benefit) expense
|
|
13,472
|
|
|
58,934
|
|
|
(59,923
|
)
|
|||
Depreciation and amortization
|
|
483,255
|
|
|
389,164
|
|
|
318,771
|
|
|||
Impairments
|
|
6,279
|
|
|
230,584
|
|
|
180,051
|
|
|||
Above-market component of swap agreements with Anadarko (1)
|
|
7,407
|
|
|
51,618
|
|
|
58,551
|
|
|||
Other expense
|
|
161,813
|
|
|
8,264
|
|
|
145
|
|
|||
Less:
|
|
|
|
|
|
|
||||||
Recognized Service revenues – fee based in excess of (less than) customer billings
|
|
(28,764
|
)
|
|
62,498
|
|
|
—
|
|
|||
Gain (loss) on divestiture and other, net
|
|
(1,406
|
)
|
|
1,312
|
|
|
132,388
|
|
|||
Equity income, net – affiliates
|
|
237,518
|
|
|
195,469
|
|
|
115,141
|
|
|||
Cash paid for maintenance capital expenditures
|
|
124,548
|
|
|
120,865
|
|
|
77,557
|
|
|||
Capitalized interest
|
|
26,980
|
|
|
32,479
|
|
|
9,074
|
|
|||
Cash paid for (reimbursement of) income taxes
|
|
96
|
|
|
2,408
|
|
|
1,194
|
|
|||
WES Operating Series A Preferred unit distributions
|
|
—
|
|
|
—
|
|
|
7,453
|
|
|||
Other income
|
|
37,792
|
|
|
2,749
|
|
|
1,384
|
|
|||
Distributable cash flow attributable to noncontrolling interests (2)
|
|
36,976
|
|
|
36,138
|
|
|
33,956
|
|
|||
Distributable cash flow (3)
|
|
$
|
1,325,445
|
|
|
$
|
1,139,587
|
|
|
$
|
1,010,850
|
|
Distributions declared
|
|
|
|
|
|
|
||||||
Distributions from WES Operating
|
|
$
|
1,128,309
|
|
|
|
|
|
||||
Less: Cash reserve for the proper conduct of WES’s business
|
|
9,360
|
|
|
|
|
|
|||||
Distributions to WES unitholders (4)
|
|
$
|
1,118,949
|
|
|
|
|
|
||||
Coverage ratio
|
|
1.18
|
|
x
|
|
|
|
(1)
|
See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
(2)
|
For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
(3)
|
For the year ended December 31, 2019, excludes cash payments of $107.7 million related to the settlement of interest-rate swap agreements. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
(4)
|
Reflects cash distributions of $2.47000 per unit declared for the year ended December 31, 2019, including the cash distribution of $0.62200 per unit paid on February 13, 2020, for the fourth-quarter 2019 distribution.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
Total revenues and other (1)
|
|
$
|
2,746,174
|
|
|
$
|
2,299,658
|
|
|
$
|
2,429,614
|
|
Equity income, net – affiliates
|
|
237,518
|
|
|
195,469
|
|
|
115,141
|
|
|||
Total operating expenses (1)
|
|
1,750,943
|
|
|
1,635,157
|
|
|
1,905,327
|
|
|||
Gain (loss) on divestiture and other, net
|
|
(1,406
|
)
|
|
1,312
|
|
|
132,388
|
|
|||
Proceeds from business interruption insurance claims (2)
|
|
—
|
|
|
—
|
|
|
29,882
|
|
|||
Operating income (loss)
|
|
1,231,343
|
|
|
861,282
|
|
|
801,698
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense
|
|
(303,286
|
)
|
|
(183,831
|
)
|
|
(142,520
|
)
|
|||
Other income (expense), net
|
|
(123,785
|
)
|
|
(4,763
|
)
|
|
1,384
|
|
|||
Income (loss) before income taxes
|
|
821,172
|
|
|
689,588
|
|
|
677,462
|
|
|||
Income tax (benefit) expense
|
|
13,472
|
|
|
58,934
|
|
|
(59,923
|
)
|
|||
Net income (loss)
|
|
807,700
|
|
|
630,654
|
|
|
737,385
|
|
|||
Net income attributable to noncontrolling interests
|
|
110,459
|
|
|
79,083
|
|
|
196,595
|
|
|||
Net income (loss) attributable to Western Midstream Partners, LP (3)
|
|
$
|
697,241
|
|
|
$
|
551,571
|
|
|
$
|
540,790
|
|
Key performance metrics (4)
|
|
|
|
|
|
|
||||||
Adjusted gross margin
|
|
$
|
2,428,077
|
|
|
$
|
1,978,205
|
|
|
$
|
1,519,869
|
|
Adjusted EBITDA
|
|
1,719,090
|
|
|
1,466,445
|
|
|
1,169,651
|
|
|||
Distributable cash flow
|
|
1,325,445
|
|
|
1,139,587
|
|
|
1,010,850
|
|
(1)
|
Revenues and other include amounts earned from services provided to our affiliates and from the sale of residue gas and NGLs to our affiliates. Operating expenses include amounts charged by our affiliates for services and reimbursements of amounts paid by affiliates to third parties on our behalf. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
(2)
|
See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
(3)
|
For reconciliations to comparable consolidated results of WES Operating, see Items Affecting the Comparability of Financial Results with WES Operating within this Item 7.
|
(4)
|
Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow are defined under the caption How We Evaluate Our Operations within this Item 7. For reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, see How We Evaluate Our Operations—Reconciliation of non-GAAP financial measures within this Item 7.
|
|
|
Year Ended December 31,
|
|||||||||||||
|
|
2019
|
|
2018
|
|
Inc/
(Dec)
|
|
2017
|
|
Inc/
(Dec)
|
|||||
Throughput for natural-gas assets (MMcf/d)
|
|
|
|
|
|
|
|
|
|
|
|||||
Gathering, treating, and transportation (1)
|
|
528
|
|
|
546
|
|
|
(3
|
)%
|
|
958
|
|
|
(43
|
)%
|
Processing (1)
|
|
3,497
|
|
|
3,231
|
|
|
8
|
%
|
|
2,592
|
|
|
25
|
%
|
Equity investment (2)
|
|
398
|
|
|
291
|
|
|
37
|
%
|
|
290
|
|
|
—
|
%
|
Total throughput
|
|
4,423
|
|
|
4,068
|
|
|
9
|
%
|
|
3,840
|
|
|
6
|
%
|
Throughput attributable to noncontrolling interests (3)
|
|
175
|
|
|
170
|
|
|
3
|
%
|
|
179
|
|
|
(5
|
)%
|
Total throughput attributable to WES for natural-gas assets
|
|
4,248
|
|
|
3,898
|
|
|
9
|
%
|
|
3,661
|
|
|
6
|
%
|
Throughput for crude-oil, NGLs, and produced-water assets (MBbls/d)
|
|
|
|
|
|
|
|
|
|
|
|||||
Gathering, treating, transportation, and disposal
|
|
876
|
|
|
534
|
|
|
64
|
%
|
|
258
|
|
|
107
|
%
|
Equity investment (4)
|
|
343
|
|
|
241
|
|
|
42
|
%
|
|
148
|
|
|
63
|
%
|
Total throughput
|
|
1,219
|
|
|
775
|
|
|
57
|
%
|
|
406
|
|
|
91
|
%
|
Throughput attributable to noncontrolling interests (3)
|
|
24
|
|
|
15
|
|
|
60
|
%
|
|
8
|
|
|
88%
|
|
Total throughput attributable to WES for crude-oil, NGLs, and produced-water assets
|
|
1,195
|
|
|
760
|
|
|
57
|
%
|
|
398
|
|
|
91
|
%
|
(1)
|
The combination of the DBM complex and DBJV and Haley systems, effective January 1, 2018, into a single complex now is referred to as the “West Texas complex,” and resulted in DBJV and Haley systems throughput previously reported as “Gathering, treating, and transportation” now being reported as “Processing.”
|
(2)
|
Represents the 14.81% share of average Fort Union throughput, 22% share of average Rendezvous throughput, 50% share of average Mi Vida and Ranch Westex throughput, and 30% share of average Red Bluff Express throughput.
|
(3)
|
For all periods presented, includes (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating, which collectively represent WES’s noncontrolling interests as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
(4)
|
Represents the 10% share of average White Cliffs throughput; 25% share of average Mont Belvieu JV throughput; 20% share of average TEG, TEP, Whitethorn, and Saddlehorn throughput; 33.33% share of average FRP throughput; and 15% share of average Panola and Cactus II throughput.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2019
|
|
2018
|
|
Inc/
(Dec)
|
|
2017
|
|
Inc/
(Dec)
|
||||||||
Service revenues – fee based
|
|
$
|
2,388,191
|
|
|
$
|
1,905,728
|
|
|
25
|
%
|
|
$
|
1,357,876
|
|
|
40
|
%
|
Service revenues – product based
|
|
70,127
|
|
|
88,785
|
|
|
(21
|
)%
|
|
—
|
|
|
NM
|
|
|||
Total service revenues
|
|
$
|
2,458,318
|
|
|
$
|
1,994,513
|
|
|
23
|
%
|
|
$
|
1,357,876
|
|
|
47
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages and
per-unit amounts
|
|
2019
|
|
2018
|
|
Inc/
(Dec)
|
|
2017
|
|
Inc/
(Dec)
|
||||||||
Natural-gas sales (1)
|
|
$
|
66,557
|
|
|
$
|
85,015
|
|
|
(22
|
)%
|
|
$
|
391,393
|
|
|
(78
|
)%
|
NGLs sales (1)
|
|
219,831
|
|
|
218,005
|
|
|
1
|
%
|
|
659,817
|
|
|
(67
|
)%
|
|||
Total Product sales
|
|
$
|
286,388
|
|
|
$
|
303,020
|
|
|
(5
|
)%
|
|
$
|
1,051,210
|
|
|
(71
|
)%
|
Per-unit gross average sales price (1):
|
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas (per Mcf)
|
|
$
|
1.65
|
|
|
$
|
2.16
|
|
|
(24
|
)%
|
|
$
|
2.92
|
|
|
(26
|
)%
|
NGLs (per Bbl)
|
|
20.93
|
|
|
31.55
|
|
|
(34
|
)%
|
|
23.88
|
|
|
32
|
%
|
(1)
|
For the years ended December 31, 2018 and 2017, includes the effects of commodity-price swap agreements for the MGR assets and DJ Basin complex, excluding the amounts considered above market with respect to these swap agreements that were recorded as capital contributions in the consolidated statements of equity and partners’ capital. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2019
|
|
2018
|
|
Inc/
(Dec)
|
|
2017
|
|
Inc/
(Dec)
|
||||||||
Other revenues
|
|
$
|
1,468
|
|
|
$
|
2,125
|
|
|
(31
|
)%
|
|
$
|
20,528
|
|
|
(90
|
)%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2019
|
|
2018
|
|
Inc/
(Dec)
|
|
2017
|
|
Inc/
(Dec)
|
||||||||
Equity income, net – affiliates
|
|
$
|
237,518
|
|
|
$
|
195,469
|
|
|
22
|
%
|
|
$
|
115,141
|
|
|
70
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2019
|
|
2018
|
|
Inc/
(Dec)
|
|
2017
|
|
Inc/
(Dec)
|
||||||||
NGLs purchases (1)
|
|
$
|
331,872
|
|
|
$
|
292,698
|
|
|
13
|
%
|
|
$
|
573,309
|
|
|
(49
|
)%
|
Residue purchases (1)
|
|
100,570
|
|
|
125,106
|
|
|
(20
|
)%
|
|
367,179
|
|
|
(66
|
)%
|
|||
Other
|
|
11,805
|
|
|
(2,299
|
)
|
|
NM
|
|
|
13,304
|
|
|
(117
|
)%
|
|||
Cost of product
|
|
444,247
|
|
|
415,505
|
|
|
7
|
%
|
|
953,792
|
|
|
(56
|
)%
|
|||
Operation and maintenance
|
|
641,219
|
|
|
480,861
|
|
|
33
|
%
|
|
345,617
|
|
|
39
|
%
|
|||
Total Cost of product and Operation and maintenance expenses
|
|
$
|
1,085,466
|
|
|
$
|
896,366
|
|
|
21
|
%
|
|
$
|
1,299,409
|
|
|
(31
|
)%
|
(1)
|
For the year ended December 31, 2017, includes the effects of the commodity-price swap agreements for the MGR assets and DJ Basin complex, excluding the amounts considered above market with respect to these swap agreements that were recorded as capital contributions in the consolidated statements of equity and partners’ capital. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2019
|
|
2018
|
|
Inc/
(Dec)
|
|
2017
|
|
Inc/
(Dec)
|
||||||||
General and administrative (1)
|
|
$
|
114,591
|
|
|
$
|
67,195
|
|
|
71
|
%
|
|
$
|
53,949
|
|
|
25
|
%
|
Property and other taxes
|
|
61,352
|
|
|
51,848
|
|
|
18
|
%
|
|
53,147
|
|
|
(2
|
)%
|
|||
Depreciation and amortization
|
|
483,255
|
|
|
389,164
|
|
|
24
|
%
|
|
318,771
|
|
|
22
|
%
|
|||
Impairments
|
|
6,279
|
|
|
230,584
|
|
|
(97
|
)%
|
|
180,051
|
|
|
28
|
%
|
|||
Total other operating expenses
|
|
$
|
665,477
|
|
|
$
|
738,791
|
|
|
(10
|
)%
|
|
$
|
605,918
|
|
|
22
|
%
|
(1)
|
Includes general and administrative expenses incurred on and subsequent to the date of the acquisition of assets from Anadarko, and a management services fee for expenses incurred by Anadarko for periods prior to the acquisition of such assets.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2019
|
|
2018
|
|
Inc/
(Dec)
|
|
2017
|
|
Inc/
(Dec)
|
||||||||
Note receivable – Anadarko
|
|
$
|
16,900
|
|
|
$
|
16,900
|
|
|
—
|
%
|
|
$
|
16,900
|
|
|
—
|
%
|
Interest income – affiliates
|
|
$
|
16,900
|
|
|
$
|
16,900
|
|
|
—
|
%
|
|
$
|
16,900
|
|
|
—
|
%
|
Third parties
|
|
|
|
|
|
|
|
|
|
|
||||||||
Long-term debt
|
|
$
|
(315,872
|
)
|
|
$
|
(200,454
|
)
|
|
58
|
%
|
|
$
|
(143,400
|
)
|
|
40
|
%
|
Amortization of debt issuance costs and commitment fees
|
|
(12,424
|
)
|
|
(9,110
|
)
|
|
36
|
%
|
|
(7,970
|
)
|
|
14
|
%
|
|||
Capitalized interest
|
|
26,980
|
|
|
32,479
|
|
|
(17
|
)%
|
|
9,074
|
|
|
NM
|
|
|||
Affiliates
|
|
|
|
|
|
|
|
|
|
|
||||||||
APCWH Note Payable
|
|
(1,833
|
)
|
|
(6,746
|
)
|
|
(73
|
)%
|
|
(153
|
)
|
|
NM
|
|
|||
Finance lease liabilities
|
|
(137
|
)
|
|
—
|
|
|
NM
|
|
|
—
|
|
|
NM
|
|
|||
Deferred purchase price obligation – Anadarko
|
|
—
|
|
|
—
|
|
|
NM
|
|
|
(71
|
)
|
|
(100
|
)%
|
|||
Interest expense
|
|
$
|
(303,286
|
)
|
|
$
|
(183,831
|
)
|
|
65
|
%
|
|
$
|
(142,520
|
)
|
|
29
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||
thousands except percentages
|
|
2019
|
|
2018
|
|
Inc/
(Dec)
|
|
2017
|
|
Inc/
(Dec)
|
||||||
Other income (expense), net
|
|
$
|
(123,785
|
)
|
|
$
|
(4,763
|
)
|
|
NM
|
|
$
|
1,384
|
|
|
NM
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2019
|
|
2018
|
|
Inc/
(Dec)
|
|
2017
|
|
Inc/
(Dec)
|
||||||||
Income (loss) before income taxes
|
|
$
|
821,172
|
|
|
$
|
689,588
|
|
|
19
|
%
|
|
$
|
677,462
|
|
|
2
|
%
|
Income tax (benefit) expense
|
|
13,472
|
|
|
58,934
|
|
|
(77
|
)%
|
|
(59,923
|
)
|
|
(198
|
)%
|
|||
Effective tax rate
|
|
2
|
%
|
|
9
|
%
|
|
|
|
NM
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages and per-unit amounts
|
|
2019
|
|
2018
|
|
Inc/
(Dec)
|
|
2017
|
|
Inc/
(Dec)
|
||||||||
Adjusted gross margin for natural-gas assets (1)
|
|
$
|
1,656,041
|
|
|
$
|
1,443,466
|
|
|
15
|
%
|
|
$
|
1,256,160
|
|
|
15
|
%
|
Adjusted gross margin for crude-oil, NGLs, and produced-water assets (1)
|
|
772,036
|
|
|
534,739
|
|
|
44
|
%
|
|
263,709
|
|
|
103
|
%
|
|||
Adjusted gross margin (1) (2)
|
|
2,428,077
|
|
|
1,978,205
|
|
|
23
|
%
|
|
1,519,869
|
|
|
30
|
%
|
|||
Per-Mcf Adjusted gross margin for natural-gas assets (3)
|
|
1.07
|
|
|
1.01
|
|
|
6
|
%
|
|
0.94
|
|
|
7
|
%
|
|||
Per-Bbl Adjusted gross margin for crude-oil, NGLs, and produced-water assets (4)
|
|
1.77
|
|
|
1.93
|
|
|
(8
|
)%
|
|
1.82
|
|
|
6
|
%
|
|||
Adjusted EBITDA (2)
|
|
1,719,090
|
|
|
1,466,445
|
|
|
17
|
%
|
|
1,169,651
|
|
|
25
|
%
|
|||
Distributable cash flow (2)
|
|
1,325,445
|
|
|
1,139,587
|
|
|
16
|
%
|
|
1,010,850
|
|
|
13
|
%
|
(1)
|
Adjusted gross margin is calculated as total revenues and other (less reimbursements for electricity-related expenses recorded as revenue), less cost of product, plus distributions from our equity investments, and excluding the noncontrolling interests owners’ proportionate share of revenues and cost of product.
|
(2)
|
For a reconciliation of Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow to the most directly comparable financial measure calculated and presented in accordance with GAAP, see the descriptions under How We Evaluate Our Operations—Reconciliation of non-GAAP financial measures within this Item 7.
|
(3)
|
Average for period. Calculated as Adjusted gross margin for natural-gas assets, divided by total throughput (MMcf/d) attributable to WES for natural-gas assets.
|
(4)
|
Average for period. Calculated as Adjusted gross margin for crude-oil, NGLs, and produced-water assets, divided by total throughput (MBbls/d) attributable to WES for crude-oil, NGLs, and produced-water assets.
|
•
|
maintenance capital expenditures, which include those expenditures required to maintain 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 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
|
|
2019
|
|
2018
|
|
2017
|
||||||
Acquisitions
|
|
$
|
2,101,229
|
|
|
$
|
162,112
|
|
|
$
|
181,708
|
|
|
|
|
|
|
|
|
||||||
Expansion capital expenditures
|
|
$
|
1,064,281
|
|
|
$
|
1,827,730
|
|
|
$
|
949,375
|
|
Maintenance capital expenditures
|
|
124,548
|
|
|
120,865
|
|
|
77,557
|
|
|||
Total capital expenditures (1) (2)
|
|
$
|
1,188,829
|
|
|
$
|
1,948,595
|
|
|
$
|
1,026,932
|
|
|
|
|
|
|
|
|
||||||
Capital incurred (1) (3)
|
|
$
|
1,055,151
|
|
|
$
|
1,910,508
|
|
|
$
|
1,252,067
|
|
(1)
|
For the years ended December 31, 2019, 2018, and 2017, included $23.3 million, $31.1 million, and $9.1 million, respectively, of capitalized interest. For the years ended December 31, 2018 and 2017, capitalized interest included $9.0 million and $2.2 million, respectively, of pre-acquisition capitalized interest for AMA.
|
(2)
|
Capital expenditures for the years ended December 31, 2018 and 2017, included $762.8 million and $353.3 million, respectively, of pre-acquisition capital expenditures for AMA. Capital expenditures for the year ended December 31, 2017, are presented net of $1.4 million of contributions in aid of construction costs from affiliates.
|
(3)
|
Capital incurred for the years ended December 31, 2018 and 2017, included $733.1 million and $453.4 million, respectively, of pre-acquisition capital incurred for AMA.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
Net cash provided by (used in):
|
|
|
|
|
|
|
||||||
Operating activities
|
|
$
|
1,324,100
|
|
|
$
|
1,348,175
|
|
|
$
|
1,042,715
|
|
Investing activities
|
|
(3,387,853
|
)
|
|
(2,210,813
|
)
|
|
(1,133,324
|
)
|
|||
Financing activities
|
|
2,071,573
|
|
|
875,192
|
|
|
(188,875
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
|
$
|
7,820
|
|
|
$
|
12,554
|
|
|
$
|
(279,484
|
)
|
•
|
$2.0 billion of cash paid for the acquisition of AMA;
|
•
|
$1.2 billion of capital expenditures, primarily related to construction and expansion at the West Texas and DJ Basin complexes, DBM oil system, and DBM water systems;
|
•
|
$128.4 million of capital contributions primarily paid to Cactus II, the TEFR Interests, Red Bluff Express, Whitethorn LLC, and White Cliffs for construction activities;
|
•
|
$92.5 million of cash paid for the acquisition of our interest in Red Bluff Express; and
|
•
|
$30.3 million of distributions received from equity investments in excess of cumulative earnings.
|
•
|
$1.9 billion of capital expenditures, primarily related to construction and expansion at the DBM oil and DBM water systems and the West Texas and DJ Basin complexes;
|
•
|
$161.9 million of cash paid for the acquisitions of our interests in Whitethorn LLC and Cactus II;
|
•
|
$133.6 million of capital contributions primarily paid to Cactus II, the TEFR Interests, Whitethorn LLC, and White Cliffs for construction activities; and
|
•
|
$29.6 million of distributions received from equity investments in excess of cumulative earnings.
|
•
|
$1.0 billion of capital expenditures, net of $1.4 million of contributions in aid of construction costs from affiliates, primarily related to construction and expansion at the DBJV system, DBM complex, DBM oil system, and DJ Basin complex and the construction of the DBM water systems;
|
•
|
$155.3 million of cash consideration paid as part of the Property Exchange;
|
•
|
$22.5 million of cash paid for the acquisition of the additional interest in Ranch Westex;
|
•
|
$3.9 million of cash paid for equipment purchases from affiliates;
|
•
|
$31.7 million of distributions received from equity investments in excess of cumulative earnings;
|
•
|
$23.3 million of net proceeds from the sale of the Helper and Clawson systems in Utah; and
|
•
|
$23.0 million of proceeds from property insurance claims attributable to the incident at the DBM complex in 2015.
|
•
|
$3.0 billion of borrowings under the Term loan facility, net of issuance costs, which were used to fund the acquisition of AMA, repay the APCWH Note Payable, and repay amounts outstanding under the RCF;
|
•
|
$1.2 billion of borrowings under the RCF, which were used for general partnership purposes, including to fund capital expenditures;
|
•
|
$458.8 million of net contributions from Anadarko representing intercompany transactions attributable to the acquisition of AMA;
|
•
|
$11.0 million of borrowings under the APCWH Note Payable, which were used to fund the construction of the DBM water systems;
|
•
|
$7.4 million of capital contributions from Anadarko related to the above-market component of swap agreements;
|
•
|
$1.0 billion of repayments of outstanding borrowings under the RCF;
|
•
|
$969.1 million of distributions paid to WES unitholders;
|
•
|
$439.6 million of repayments of the total outstanding balance under the APCWH Note Payable;
|
•
|
$118.2 million of distributions paid to the noncontrolling interest owners of WES Operating;
|
•
|
$28.0 million of repayments of the total outstanding balance under the WGP RCF, which matured in March 2019; and
|
•
|
$9.7 million of distributions paid to the noncontrolling interest owner of Chipeta.
|
•
|
$1.08 billion of net proceeds from the offering of the 4.500% Senior Notes due 2028 and 5.300% Senior Notes due 2048 in March 2018, after underwriting and original issue discounts and offering costs, which were used to repay amounts outstanding under the RCF and for general partnership purposes, including to fund capital expenditures;
|
•
|
$738.1 million of net proceeds from the offering of the 4.750% Senior Notes due 2028 and 5.500% Senior Notes due 2048 in August 2018, after underwriting and original issue discounts and offering costs, which were used to repay the maturing 2.600% Senior Notes due August 2018, repay amounts outstanding under the RCF, and for general partnership purposes, including to fund capital expenditures;
|
•
|
$534.2 million of borrowings under the RCF, net of extension and amendment costs, which were used for general partnership purposes, including to fund capital expenditures;
|
•
|
$321.8 million of borrowings under the APCWH Note Payable, which were used to fund the construction of the DBM water systems;
|
•
|
$97.8 million of net contributions from Anadarko representing intercompany transactions attributable to the acquisition of AMA;
|
•
|
$51.6 million of capital contributions from Anadarko related to the above-market component of swap agreements;
|
•
|
$690.0 million of repayments of outstanding borrowings under the RCF;
|
•
|
$502.5 million of distributions paid to WES unitholders;
|
•
|
$386.3 million of distributions paid to the noncontrolling interest owners of WES Operating;
|
•
|
$350.0 million of principal repayment on the maturing 2.600% Senior Notes due August 2018;
|
•
|
$13.5 million of distributions paid to the noncontrolling interest owner of Chipeta; and
|
•
|
$3.4 million of issuance costs incurred in connection with the Term loan facility.
|
•
|
$370.0 million of borrowings under the RCF, which were used for general partnership purposes, including funding of capital expenditures;
|
•
|
$126.9 million of net contributions from Anadarko representing intercompany transactions attributable to the acquisition of AMA;
|
•
|
$98.8 million of borrowings under the APCWH Note Payable, which were used to fund the construction of the DBM water systems;
|
•
|
$58.6 million of capital contributions from Anadarko related to the above-market component of swap agreements;
|
•
|
$442.0 million of distributions paid to WES unitholders;
|
•
|
$355.6 million of distributions paid to the noncontrolling interest owners of WES Operating;
|
•
|
$37.3 million of cash paid to Anadarko for the settlement of the Deferred purchase price obligation – Anadarko; and
|
•
|
$13.6 million of distributions paid to the noncontrolling interest owner of Chipeta.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
Net income (loss) attributable to WES
|
|
$
|
697,241
|
|
|
$
|
551,571
|
|
|
$
|
540,790
|
|
Limited partner interests in WES Operating not held by WES (1)
|
|
103,364
|
|
|
70,474
|
|
|
185,860
|
|
|||
General and administrative expenses (2)
|
|
6,819
|
|
|
4,029
|
|
|
2,872
|
|
|||
Other income (expense), net
|
|
(79
|
)
|
|
(192
|
)
|
|
(85
|
)
|
|||
Interest expense
|
|
245
|
|
|
2,035
|
|
|
2,229
|
|
|||
Net income (loss) attributable to WES Operating
|
|
$
|
807,590
|
|
|
$
|
627,917
|
|
|
$
|
731,666
|
|
(1)
|
Represents the portion of net income (loss) allocated to the limited partner interests in WES Operating not held by WES. As of December 31, 2019, 2018, and 2017, the public held a 0%, 59.2%, and 59.6% limited partner interest in WES Operating, respectively. Certain subsidiaries of Occidental separately held a 2.0%, 9.7%, and 9.1% limited partner interest in WES Operating as of December 31, 2019, 2018, and 2017, respectively. Immediately prior to the Merger closing, the WES Operating IDRs and the general partner units were converted into a non-economic general partner interest in WES Operating and WES Operating common units, and at Merger completion, all WES Operating common units held by the public and subsidiaries of Anadarko (other than common units held by WES, WES Operating GP, and 6.4 million common units held by a subsidiary of Anadarko) were converted into WES common units. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
(2)
|
Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
WES net cash provided by operating activities
|
|
$
|
1,324,100
|
|
|
$
|
1,348,175
|
|
|
$
|
1,042,715
|
|
General and administrative expenses (1)
|
|
6,819
|
|
|
4,029
|
|
|
2,872
|
|
|||
Non-cash equity-based compensation expense
|
|
(1,259
|
)
|
|
(278
|
)
|
|
(247
|
)
|
|||
Changes in working capital
|
|
2,383
|
|
|
(854
|
)
|
|
(8
|
)
|
|||
Other income (expense), net
|
|
(79
|
)
|
|
(192
|
)
|
|
(85
|
)
|
|||
Interest expense
|
|
245
|
|
|
2,035
|
|
|
2,229
|
|
|||
Debt related amortization and other items, net
|
|
(20
|
)
|
|
(801
|
)
|
|
(678
|
)
|
|||
WES Operating net cash provided by operating activities
|
|
$
|
1,332,189
|
|
|
$
|
1,352,114
|
|
|
$
|
1,046,798
|
|
|
|
|
|
|
|
|
||||||
WES net cash provided by (used in) financing activities
|
|
$
|
2,071,573
|
|
|
$
|
875,192
|
|
|
$
|
(188,875
|
)
|
Distributions to WES unitholders (2)
|
|
969,073
|
|
|
502,457
|
|
|
441,967
|
|
|||
Distributions to WES from WES Operating (3)
|
|
(1,006,163
|
)
|
|
(507,323
|
)
|
|
(445,677
|
)
|
|||
Registration expenses related to the issuance of WES common units
|
|
855
|
|
|
—
|
|
|
—
|
|
|||
WGP RCF costs
|
|
—
|
|
|
7
|
|
|
—
|
|
|||
WGP RCF repayments
|
|
28,000
|
|
|
—
|
|
|
—
|
|
|||
WES Operating net cash provided by (used in) financing activities
|
|
$
|
2,063,338
|
|
|
$
|
870,333
|
|
|
$
|
(192,585
|
)
|
(1)
|
Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.
|
(2)
|
Represents distributions to WES common unitholders paid under WES’s partnership agreement. See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
(3)
|
Difference attributable to elimination upon consolidation of WES Operating’s distributions on partnership interests owned by WES. See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
|
|
|
Obligations by Period
|
||||||||||||||||||||||||||
thousands
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
2024
|
|
Thereafter
|
|
Total
|
||||||||||||||
Total debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Principal
|
|
$
|
3,007,873
|
|
|
$
|
500,000
|
|
|
$
|
670,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,830,000
|
|
|
$
|
8,007,873
|
|
Interest
|
|
331,192
|
|
|
217,990
|
|
|
207,589
|
|
|
180,963
|
|
|
180,963
|
|
|
2,136,237
|
|
|
3,254,934
|
|
|||||||
Asset retirement obligations
|
|
22,472
|
|
|
38,537
|
|
|
—
|
|
|
—
|
|
|
4,443
|
|
|
293,416
|
|
|
358,868
|
|
|||||||
Capital expenditures
|
|
140,954
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
140,954
|
|
|||||||
Credit facility fees
|
|
4,133
|
|
|
4,133
|
|
|
4,133
|
|
|
4,133
|
|
|
4,133
|
|
|
530
|
|
|
21,195
|
|
|||||||
Environmental obligations
|
|
3,528
|
|
|
907
|
|
|
468
|
|
|
320
|
|
|
203
|
|
|
12
|
|
|
5,438
|
|
|||||||
Operating leases
|
|
1,969
|
|
|
612
|
|
|
618
|
|
|
625
|
|
|
449
|
|
|
1,209
|
|
|
5,482
|
|
|||||||
Total
|
|
$
|
3,512,121
|
|
|
$
|
762,179
|
|
|
$
|
882,808
|
|
|
$
|
186,041
|
|
|
$
|
190,191
|
|
|
$
|
6,261,404
|
|
|
$
|
11,794,744
|
|
WESTERN MIDSTREAM PARTNERS, LP
|
|
|
|
/s/ Michael P. Ure
|
|
Michael P. Ure
President and Chief Executive Officer
Western Midstream Holdings, LLC
(as general partner of Western Midstream Partners, LP)
|
|
|
|
/s/ Michael C. Pearl
|
|
Michael C. Pearl
Senior Vice President and Chief Financial Officer
Western Midstream Holdings, LLC
(as general partner of Western Midstream Partners, LP)
|
|
|
|
WESTERN MIDSTREAM OPERATING, LP
|
|
|
|
/s/ Michael P. Ure
|
|
Michael P. Ure
President and Chief Executive Officer
Western Midstream Operating GP, LLC
(as general partner of Western Midstream Operating, LP)
|
|
|
|
/s/ Michael C. Pearl
|
|
Michael C. Pearl
Senior Vice President and Chief Financial Officer
Western Midstream Operating GP, LLC
(as general partner of Western Midstream Operating, LP)
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands except per-unit amounts
|
|
2019
|
|
2018
|
|
2017
|
||||||
Revenues and other – affiliates
|
|
|
|
|
|
|
||||||
Service revenues – fee based
|
|
$
|
1,441,875
|
|
|
$
|
1,070,066
|
|
|
$
|
769,305
|
|
Service revenues – product based
|
|
7,062
|
|
|
3,339
|
|
|
—
|
|
|||
Product sales
|
|
158,459
|
|
|
280,306
|
|
|
753,724
|
|
|||
Other
|
|
—
|
|
|
—
|
|
|
16,076
|
|
|||
Total revenues and other – affiliates
|
|
1,607,396
|
|
|
1,353,711
|
|
|
1,539,105
|
|
|||
Revenues and other – third parties
|
|
|
|
|
|
|
||||||
Service revenues – fee based
|
|
946,316
|
|
|
835,662
|
|
|
588,571
|
|
|||
Service revenues – product based
|
|
63,065
|
|
|
85,446
|
|
|
—
|
|
|||
Product sales
|
|
127,929
|
|
|
22,714
|
|
|
297,486
|
|
|||
Other
|
|
1,468
|
|
|
2,125
|
|
|
4,452
|
|
|||
Total revenues and other – third parties
|
|
1,138,778
|
|
|
945,947
|
|
|
890,509
|
|
|||
Total revenues and other
|
|
2,746,174
|
|
|
2,299,658
|
|
|
2,429,614
|
|
|||
Equity income, net – affiliates
|
|
237,518
|
|
|
195,469
|
|
|
115,141
|
|
|||
Operating expenses
|
|
|
|
|
|
|
||||||
Cost of product (1)
|
|
444,247
|
|
|
415,505
|
|
|
953,792
|
|
|||
Operation and maintenance (1)
|
|
641,219
|
|
|
480,861
|
|
|
345,617
|
|
|||
General and administrative (1)
|
|
114,591
|
|
|
67,195
|
|
|
53,949
|
|
|||
Property and other taxes
|
|
61,352
|
|
|
51,848
|
|
|
53,147
|
|
|||
Depreciation and amortization
|
|
483,255
|
|
|
389,164
|
|
|
318,771
|
|
|||
Impairments
|
|
6,279
|
|
|
230,584
|
|
|
180,051
|
|
|||
Total operating expenses
|
|
1,750,943
|
|
|
1,635,157
|
|
|
1,905,327
|
|
|||
Gain (loss) on divestiture and other, net (2)
|
|
(1,406
|
)
|
|
1,312
|
|
|
132,388
|
|
|||
Proceeds from business interruption insurance claims
|
|
—
|
|
|
—
|
|
|
29,882
|
|
|||
Operating income (loss)
|
|
1,231,343
|
|
|
861,282
|
|
|
801,698
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense (3)
|
|
(303,286
|
)
|
|
(183,831
|
)
|
|
(142,520
|
)
|
|||
Other income (expense), net (4)
|
|
(123,785
|
)
|
|
(4,763
|
)
|
|
1,384
|
|
|||
Income (loss) before income taxes
|
|
821,172
|
|
|
689,588
|
|
|
677,462
|
|
|||
Income tax expense (benefit)
|
|
13,472
|
|
|
58,934
|
|
|
(59,923
|
)
|
|||
Net income (loss)
|
|
807,700
|
|
|
630,654
|
|
|
737,385
|
|
|||
Net income (loss) attributable to noncontrolling interests
|
|
110,459
|
|
|
79,083
|
|
|
196,595
|
|
|||
Net income (loss) attributable to Western Midstream Partners, LP
|
|
$
|
697,241
|
|
|
$
|
551,571
|
|
|
$
|
540,790
|
|
Limited partners’ interest in net income (loss):
|
|
|
|
|
|
|
||||||
Net income (loss) attributable to Western Midstream Partners, LP
|
|
$
|
697,241
|
|
|
$
|
551,571
|
|
|
$
|
540,790
|
|
Pre-acquisition net (income) loss allocated to Anadarko
|
|
(29,279
|
)
|
|
(182,142
|
)
|
|
(164,183
|
)
|
|||
General partner interest in net (income) loss
|
|
(5,637
|
)
|
|
—
|
|
|
—
|
|
|||
Limited partners’ interest in net income (loss) (5)
|
|
662,325
|
|
|
369,429
|
|
|
376,607
|
|
|||
Net income (loss) per common unit – basic and diluted (5)
|
|
$
|
1.59
|
|
|
$
|
1.69
|
|
|
$
|
1.72
|
|
Weighted-average common units outstanding – basic and diluted
|
|
415,794
|
|
|
218,936
|
|
|
218,931
|
|
(1)
|
Cost of product includes product purchases from affiliates (as defined in Note 1) of $254.8 million, $168.5 million, and $74.6 million for the years ended December 31, 2019, 2018, and 2017, respectively. Operation and maintenance includes charges from affiliates of $147.0 million, $115.9 million, and $82.2 million for the years ended December 31, 2019, 2018, and 2017, respectively. General and administrative includes charges from affiliates of $101.5 million, $49.7 million, and $43.2 million for the years ended December 31, 2019, 2018, and 2017, respectively. See Note 6.
|
(2)
|
Includes losses related to an incident at the DBM complex for the year ended December 31, 2017. See Note 1.
|
(3)
|
Includes affiliate amounts of $(2.0) million, $(6.7) million, and $(0.2) million for the years ended December 31, 2019, 2018, and 2017, respectively. See Note 1 and Note 13.
|
(4)
|
Includes losses associated with the interest-rate swap agreements for the years ended December 31, 2019 and 2018. See Note 13.
|
(5)
|
See Note 1.
|
|
|
December 31,
|
||||||
thousands except number of units
|
|
2019
|
|
2018
|
||||
ASSETS
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
99,962
|
|
|
$
|
92,142
|
|
Accounts receivable, net (1)
|
|
260,512
|
|
|
221,164
|
|
||
Other current assets (2)
|
|
41,938
|
|
|
31,458
|
|
||
Total current assets
|
|
402,412
|
|
|
344,764
|
|
||
Note receivable – Anadarko
|
|
260,000
|
|
|
260,000
|
|
||
Property, plant, and equipment
|
|
|
|
|
||||
Cost
|
|
12,355,671
|
|
|
11,258,773
|
|
||
Less accumulated depreciation
|
|
3,290,740
|
|
|
2,848,420
|
|
||
Net property, plant, and equipment
|
|
9,064,931
|
|
|
8,410,353
|
|
||
Goodwill
|
|
445,800
|
|
|
445,800
|
|
||
Other intangible assets
|
|
809,391
|
|
|
841,408
|
|
||
Equity investments
|
|
1,285,717
|
|
|
1,092,088
|
|
||
Other assets (3)
|
|
78,202
|
|
|
62,792
|
|
||
Total assets
|
|
$
|
12,346,453
|
|
|
$
|
11,457,205
|
|
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accounts and imbalance payables
|
|
$
|
293,128
|
|
|
$
|
443,343
|
|
Short-term debt (4)
|
|
7,873
|
|
|
28,000
|
|
||
Accrued ad valorem taxes
|
|
35,160
|
|
|
36,986
|
|
||
Accrued liabilities (5)
|
|
149,793
|
|
|
129,148
|
|
||
Total current liabilities
|
|
485,954
|
|
|
637,477
|
|
||
Long-term liabilities
|
|
|
|
|
||||
Long-term debt
|
|
7,951,565
|
|
|
4,787,381
|
|
||
APCWH Note Payable (6)
|
|
—
|
|
|
427,493
|
|
||
Deferred income taxes
|
|
18,899
|
|
|
280,017
|
|
||
Asset retirement obligations
|
|
336,396
|
|
|
300,024
|
|
||
Other liabilities (7)
|
|
208,346
|
|
|
132,130
|
|
||
Total long-term liabilities
|
|
8,515,206
|
|
|
5,927,045
|
|
||
Total liabilities
|
|
9,001,160
|
|
|
6,564,522
|
|
||
Equity and partners’ capital
|
|
|
|
|
||||
Common units (443,971,409 and 218,937,797 units issued and outstanding at December 31, 2019 and 2018, respectively)
|
|
3,209,947
|
|
|
951,888
|
|
||
General partner units (9,060,641 and zero units issued and outstanding at December 31, 2019 and 2018, respectively) (8)
|
|
(14,224
|
)
|
|
—
|
|
||
Net investment by Anadarko
|
|
—
|
|
|
1,388,018
|
|
||
Total partners’ capital
|
|
3,195,723
|
|
|
2,339,906
|
|
||
Noncontrolling interests
|
|
149,570
|
|
|
2,552,777
|
|
||
Total equity and partners’ capital
|
|
3,345,293
|
|
|
4,892,683
|
|
||
Total liabilities, equity and partners’ capital
|
|
$
|
12,346,453
|
|
|
$
|
11,457,205
|
|
(1)
|
Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $113.3 million and $72.6 million as of December 31, 2019 and 2018, respectively.
|
(2)
|
Other current assets includes affiliate amounts of $5.0 million and $3.7 million as of December 31, 2019 and 2018, respectively.
|
(3)
|
Other assets includes affiliate amounts of $60.2 million and $42.2 million as of December 31, 2019 and 2018, respectively. Other assets also includes $4.5 million and $5.3 million of NGLs line fill as of December 31, 2019 and 2018, respectively.
|
(4)
|
As of December 31, 2019, all amounts are considered affiliate. See Note 14.
|
(5)
|
Accrued liabilities includes affiliate amounts of $3.1 million and $2.2 million as of December 31, 2019 and 2018, respectively.
|
(6)
|
See Note 1 and Note 6.
|
(7)
|
Other liabilities includes affiliate amounts of $97.8 million and $47.8 million as of December 31, 2019 and 2018, respectively.
|
(8)
|
See Note 1.
|
|
|
Partners’ Capital
|
|
|
|
|
||||||||||||||
thousands
|
|
Net
Investment
by Anadarko
|
|
Common
Units
|
|
General Partner
Units
|
|
Noncontrolling
Interests
|
|
Total
|
||||||||||
Balance at December 31, 2016
|
|
$
|
761,890
|
|
|
$
|
1,048,143
|
|
|
$
|
—
|
|
|
$
|
3,062,623
|
|
|
$
|
4,872,656
|
|
Net income (loss)
|
|
164,183
|
|
|
376,607
|
|
|
—
|
|
|
196,595
|
|
|
737,385
|
|
|||||
Above-market component of swap agreements with Anadarko (1)
|
|
—
|
|
|
58,551
|
|
|
—
|
|
|
—
|
|
|
58,551
|
|
|||||
WES Operating equity transactions, net (2)
|
|
—
|
|
|
6,615
|
|
|
—
|
|
|
(6,798
|
)
|
|
(183
|
)
|
|||||
Distributions to Chipeta noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13,569
|
)
|
|
(13,569
|
)
|
|||||
Distributions to noncontrolling interest owners of WES Operating
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(355,623
|
)
|
|
(355,623
|
)
|
|||||
Distributions to Partnership unitholders
|
|
—
|
|
|
(441,967
|
)
|
|
—
|
|
|
—
|
|
|
(441,967
|
)
|
|||||
Acquisitions from affiliates
|
|
(1,263
|
)
|
|
1,263
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Revision to Deferred purchase price obligation – Anadarko (3)
|
|
—
|
|
|
4,165
|
|
|
—
|
|
|
—
|
|
|
4,165
|
|
|||||
Contributions of equity-based compensation from Anadarko
|
|
—
|
|
|
4,587
|
|
|
—
|
|
|
—
|
|
|
4,587
|
|
|||||
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
126,866
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
126,866
|
|
|||||
Net contributions from (distributions to) Anadarko of other assets
|
|
—
|
|
|
3,189
|
|
|
—
|
|
|
—
|
|
|
3,189
|
|
|||||
Adjustments of net deferred tax liabilities
|
|
(1,505
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,505
|
)
|
|||||
Other
|
|
—
|
|
|
(28
|
)
|
|
—
|
|
|
526
|
|
|
498
|
|
|||||
Balance at December 31, 2017
|
|
$
|
1,050,171
|
|
|
$
|
1,061,125
|
|
|
$
|
—
|
|
|
$
|
2,883,754
|
|
|
$
|
4,995,050
|
|
Cumulative effect of accounting change (4)
|
|
629
|
|
|
(14,200
|
)
|
|
—
|
|
|
(30,179
|
)
|
|
(43,750
|
)
|
|||||
Net income (loss)
|
|
182,142
|
|
|
369,429
|
|
|
—
|
|
|
79,083
|
|
|
630,654
|
|
|||||
Above-market component of swap agreements with Anadarko (1)
|
|
—
|
|
|
51,618
|
|
|
—
|
|
|
—
|
|
|
51,618
|
|
|||||
WES Operating equity transactions, net (2)
|
|
—
|
|
|
(19,577
|
)
|
|
—
|
|
|
19,577
|
|
|
—
|
|
|||||
Distributions to Chipeta noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13,529
|
)
|
|
(13,529
|
)
|
|||||
Distributions to noncontrolling interest owners of WES Operating
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(386,326
|
)
|
|
(386,326
|
)
|
|||||
Distributions to Partnership unitholders
|
|
—
|
|
|
(502,457
|
)
|
|
—
|
|
|
—
|
|
|
(502,457
|
)
|
|||||
Contributions of equity-based compensation from Anadarko
|
|
—
|
|
|
5,741
|
|
|
—
|
|
|
—
|
|
|
5,741
|
|
|||||
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
97,755
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
97,755
|
|
|||||
Net contributions from (distributions to) Anadarko of other assets
|
|
58,835
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
58,835
|
|
|||||
Adjustments of net deferred tax liabilities
|
|
(1,514
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,514
|
)
|
|||||
Other
|
|
—
|
|
|
209
|
|
|
—
|
|
|
397
|
|
|
606
|
|
|||||
Balance at December 31, 2018
|
|
$
|
1,388,018
|
|
|
$
|
951,888
|
|
|
$
|
—
|
|
|
$
|
2,552,777
|
|
|
$
|
4,892,683
|
|
Net income (loss)
|
|
29,279
|
|
|
662,325
|
|
|
5,637
|
|
|
110,459
|
|
|
807,700
|
|
|||||
Cumulative impact of the Merger transactions (5)
|
|
—
|
|
|
3,169,800
|
|
|
—
|
|
|
(3,169,800
|
)
|
|
—
|
|
|||||
Issuance of general partner units (5)
|
|
—
|
|
|
19,861
|
|
|
(19,861
|
)
|
|
—
|
|
|
—
|
|
|||||
Above-market component of swap agreements with Anadarko (1)
|
|
—
|
|
|
7,407
|
|
|
—
|
|
|
—
|
|
|
7,407
|
|
|||||
WES Operating equity transactions, net (2)
|
|
—
|
|
|
(755,197
|
)
|
|
—
|
|
|
755,197
|
|
|
—
|
|
|||||
Distributions to Chipeta noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(9,663
|
)
|
|
(9,663
|
)
|
|||||
Distributions to noncontrolling interest owners of WES Operating
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(118,225
|
)
|
|
(118,225
|
)
|
|||||
Distributions to Partnership unitholders
|
|
—
|
|
|
(969,073
|
)
|
|
—
|
|
|
—
|
|
|
(969,073
|
)
|
|||||
Acquisitions from affiliates (6)
|
|
(2,149,218
|
)
|
|
112,872
|
|
|
—
|
|
|
28,845
|
|
|
(2,007,501
|
)
|
|||||
Contributions of equity-based compensation from Occidental
|
|
—
|
|
|
13,968
|
|
|
—
|
|
|
—
|
|
|
13,968
|
|
|||||
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
458,819
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
458,819
|
|
|||||
Net contributions from (distributions to) Occidental of other assets
|
|
—
|
|
|
(90
|
)
|
|
—
|
|
|
—
|
|
|
(90
|
)
|
|||||
Adjustments of net deferred tax liabilities
|
|
273,102
|
|
|
(4,375
|
)
|
|
—
|
|
|
—
|
|
|
268,727
|
|
|||||
Other
|
|
—
|
|
|
561
|
|
|
—
|
|
|
(20
|
)
|
|
541
|
|
|||||
Balance at December 31, 2019
|
|
$
|
—
|
|
|
$
|
3,209,947
|
|
|
$
|
(14,224
|
)
|
|
$
|
149,570
|
|
|
$
|
3,345,293
|
|
(1)
|
See Note 6.
|
(2)
|
For the years ended December 31, 2019, 2018, and 2017, the $(755.2) million, $(19.6) million, and $6.6 million increase (decrease) to partners’ capital, respectively, together with net income (loss) attributable to Western Midstream Partners, LP, totaled $(58.0) million, $532.0 million, and $547.4 million, respectively.
|
(3)
|
See Note 3.
|
(4)
|
Includes the adoption of Revenue from Contracts with Customers (Topic 606) on January 1, 2018. See Note 1.
|
(5)
|
See Note 1.
|
(6)
|
The amounts allocated to common unitholders and noncontrolling interests represent a non-cash investing activity related to the assets and liabilities assumed in the AMA acquisition.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
Cash flows from operating activities
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
807,700
|
|
|
$
|
630,654
|
|
|
$
|
737,385
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
Depreciation and amortization
|
|
483,255
|
|
|
389,164
|
|
|
318,771
|
|
|||
Impairments
|
|
6,279
|
|
|
230,584
|
|
|
180,051
|
|
|||
Non-cash equity-based compensation expense
|
|
15,494
|
|
|
6,431
|
|
|
5,169
|
|
|||
Deferred income taxes
|
|
7,609
|
|
|
139,048
|
|
|
(53,138
|
)
|
|||
Accretion and amortization of long-term obligations, net
|
|
8,441
|
|
|
5,943
|
|
|
4,932
|
|
|||
Equity income, net – affiliates
|
|
(237,518
|
)
|
|
(195,469
|
)
|
|
(115,141
|
)
|
|||
Distributions from equity-investment earnings – affiliates
|
|
234,572
|
|
|
187,392
|
|
|
117,093
|
|
|||
(Gain) loss on divestiture and other, net (1)
|
|
1,406
|
|
|
(1,312
|
)
|
|
(132,388
|
)
|
|||
(Gain) loss on interest-rate swaps
|
|
125,334
|
|
|
7,972
|
|
|
—
|
|
|||
Cash paid to settle interest-rate swaps
|
|
(107,685
|
)
|
|
—
|
|
|
—
|
|
|||
Lower of cost or market inventory adjustments
|
|
236
|
|
|
752
|
|
|
145
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
|
||||||
(Increase) decrease in accounts receivable, net
|
|
(45,033
|
)
|
|
(60,502
|
)
|
|
(16,244
|
)
|
|||
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net
|
|
(30,866
|
)
|
|
45,605
|
|
|
(937
|
)
|
|||
Change in other items, net
|
|
54,876
|
|
|
(38,087
|
)
|
|
(2,983
|
)
|
|||
Net cash provided by operating activities
|
|
1,324,100
|
|
|
1,348,175
|
|
|
1,042,715
|
|
|||
Cash flows from investing activities
|
|
|
|
|
|
|
||||||
Capital expenditures
|
|
(1,188,829
|
)
|
|
(1,948,595
|
)
|
|
(1,028,319
|
)
|
|||
Contributions in aid of construction costs from affiliates
|
|
—
|
|
|
—
|
|
|
1,387
|
|
|||
Acquisitions from affiliates
|
|
(2,007,926
|
)
|
|
(254
|
)
|
|
(3,910
|
)
|
|||
Acquisitions from third parties
|
|
(93,303
|
)
|
|
(161,858
|
)
|
|
(177,798
|
)
|
|||
Investments in equity affiliates
|
|
(128,393
|
)
|
|
(133,629
|
)
|
|
(2,884
|
)
|
|||
Distributions from equity investments in excess of cumulative earnings – affiliates
|
|
30,256
|
|
|
29,585
|
|
|
31,659
|
|
|||
Proceeds from the sale of assets to third parties
|
|
342
|
|
|
3,938
|
|
|
23,564
|
|
|||
Proceeds from property insurance claims
|
|
—
|
|
|
—
|
|
|
22,977
|
|
|||
Net cash used in investing activities
|
|
(3,387,853
|
)
|
|
(2,210,813
|
)
|
|
(1,133,324
|
)
|
|||
Cash flows from financing activities
|
|
|
|
|
|
|
||||||
Borrowings, net of debt issuance costs (2)
|
|
4,169,695
|
|
|
2,671,337
|
|
|
468,803
|
|
|||
Repayments of debt (3)
|
|
(1,467,595
|
)
|
|
(1,040,000
|
)
|
|
—
|
|
|||
Settlement of the Deferred purchase price obligation – Anadarko (4)
|
|
—
|
|
|
—
|
|
|
(37,346
|
)
|
|||
Increase (decrease) in outstanding checks
|
|
1,571
|
|
|
(3,206
|
)
|
|
5,593
|
|
|||
Proceeds from the issuance of WES Operating common units, net of offering expenses
|
|
—
|
|
|
—
|
|
|
(183
|
)
|
|||
Registration expenses related to the issuance of Partnership common units
|
|
(855
|
)
|
|
—
|
|
|
—
|
|
|||
Distributions to Partnership unitholders (5)
|
|
(969,073
|
)
|
|
(502,457
|
)
|
|
(441,967
|
)
|
|||
Distributions to Chipeta noncontrolling interest owner
|
|
(9,663
|
)
|
|
(13,529
|
)
|
|
(13,569
|
)
|
|||
Distributions to noncontrolling interest owners of WES Operating
|
|
(118,225
|
)
|
|
(386,326
|
)
|
|
(355,623
|
)
|
|||
Net contributions from (distributions to) Anadarko
|
|
458,819
|
|
|
97,755
|
|
|
126,866
|
|
|||
Above-market component of swap agreements with Anadarko (5)
|
|
7,407
|
|
|
51,618
|
|
|
58,551
|
|
|||
Finance lease payments – affiliates
|
|
(508
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash provided by (used in) financing activities
|
|
2,071,573
|
|
|
875,192
|
|
|
(188,875
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
|
7,820
|
|
|
12,554
|
|
|
(279,484
|
)
|
|||
Cash and cash equivalents at beginning of period
|
|
92,142
|
|
|
79,588
|
|
|
359,072
|
|
|||
Cash and cash equivalents at end of period
|
|
$
|
99,962
|
|
|
$
|
92,142
|
|
|
$
|
79,588
|
|
Supplemental disclosures
|
|
|
|
|
|
|
||||||
Accretion expense and revisions to the Deferred purchase price obligation – Anadarko (4)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(4,094
|
)
|
Net distributions to (contributions from) Anadarko of other assets
|
|
90
|
|
|
(58,835
|
)
|
|
(3,189
|
)
|
|||
Interest paid, net of capitalized interest
|
|
293,795
|
|
|
140,720
|
|
|
136,624
|
|
|||
Taxes paid (reimbursements received)
|
|
96
|
|
|
2,408
|
|
|
1,194
|
|
|||
Accrued capital expenditures
|
|
140,954
|
|
|
274,632
|
|
|
312,720
|
|
|||
Fair value of properties and equipment from non-cash third-party transactions (4)
|
|
—
|
|
|
—
|
|
|
551,453
|
|
(1)
|
Includes losses related to an incident at the DBM complex for the year ended December 31, 2017. See Note 1.
|
(2)
|
For the years ended December 31, 2019 and 2018, includes $11.0 million and $321.8 million of borrowings, respectively, under the APCWH Note Payable.
|
(3)
|
For the year ended December 31, 2019, includes a $439.6 million repayment to settle the APCWH Note Payable. See Note 6.
|
(4)
|
See Note 3.
|
(5)
|
See Note 6.
|
|
|
Year Ended December 31,
|
||||||||||
thousands except per-unit amounts
|
|
2019
|
|
2018
|
|
2017
|
||||||
Revenues and other – affiliates
|
|
|
|
|
|
|
||||||
Service revenues – fee based
|
|
$
|
1,441,875
|
|
|
$
|
1,070,066
|
|
|
$
|
769,305
|
|
Service revenues – product based
|
|
7,062
|
|
|
3,339
|
|
|
—
|
|
|||
Product sales
|
|
158,459
|
|
|
280,306
|
|
|
753,724
|
|
|||
Other
|
|
—
|
|
|
—
|
|
|
16,076
|
|
|||
Total revenues and other – affiliates
|
|
1,607,396
|
|
|
1,353,711
|
|
|
1,539,105
|
|
|||
Revenues and other – third parties
|
|
|
|
|
|
|
||||||
Service revenues – fee based
|
|
946,316
|
|
|
835,662
|
|
|
588,571
|
|
|||
Service revenues – product based
|
|
63,065
|
|
|
85,446
|
|
|
—
|
|
|||
Product sales
|
|
127,929
|
|
|
22,714
|
|
|
297,486
|
|
|||
Other
|
|
1,468
|
|
|
2,125
|
|
|
4,452
|
|
|||
Total revenues and other – third parties
|
|
1,138,778
|
|
|
945,947
|
|
|
890,509
|
|
|||
Total revenues and other
|
|
2,746,174
|
|
|
2,299,658
|
|
|
2,429,614
|
|
|||
Equity income, net – affiliates
|
|
237,518
|
|
|
195,469
|
|
|
115,141
|
|
|||
Operating expenses
|
|
|
|
|
|
|
||||||
Cost of product (1)
|
|
444,247
|
|
|
415,505
|
|
|
953,792
|
|
|||
Operation and maintenance (1)
|
|
641,219
|
|
|
480,861
|
|
|
345,617
|
|
|||
General and administrative (1)
|
|
107,772
|
|
|
63,166
|
|
|
51,077
|
|
|||
Property and other taxes
|
|
61,352
|
|
|
51,848
|
|
|
53,147
|
|
|||
Depreciation and amortization
|
|
483,255
|
|
|
389,164
|
|
|
318,771
|
|
|||
Impairments
|
|
6,279
|
|
|
230,584
|
|
|
180,051
|
|
|||
Total operating expenses
|
|
1,744,124
|
|
|
1,631,128
|
|
|
1,902,455
|
|
|||
Gain (loss) on divestiture and other, net (2)
|
|
(1,406
|
)
|
|
1,312
|
|
|
132,388
|
|
|||
Proceeds from business interruption insurance claims
|
|
—
|
|
|
—
|
|
|
29,882
|
|
|||
Operating income (loss)
|
|
1,238,162
|
|
|
865,311
|
|
|
804,570
|
|
|||
Interest income – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense (3)
|
|
(303,041
|
)
|
|
(181,796
|
)
|
|
(140,291
|
)
|
|||
Other income (expense), net (4)
|
|
(123,864
|
)
|
|
(4,955
|
)
|
|
1,299
|
|
|||
Income (loss) before income taxes
|
|
828,157
|
|
|
695,460
|
|
|
682,478
|
|
|||
Income tax expense (benefit)
|
|
13,472
|
|
|
58,934
|
|
|
(59,923
|
)
|
|||
Net income (loss)
|
|
814,685
|
|
|
636,526
|
|
|
742,401
|
|
|||
Net income attributable to noncontrolling interest
|
|
7,095
|
|
|
8,609
|
|
|
10,735
|
|
|||
Net income (loss) attributable to Western Midstream Operating, LP
|
|
$
|
807,590
|
|
|
$
|
627,917
|
|
|
$
|
731,666
|
|
Limited partners’ interest in net income (loss):
|
|
|
|
|
|
|
||||||
Net income (loss) attributable to Western Midstream Operating, LP
|
|
$
|
807,590
|
|
|
$
|
627,917
|
|
|
$
|
731,666
|
|
Pre-acquisition net (income) loss allocated to Anadarko
|
|
(29,279
|
)
|
|
(182,142
|
)
|
|
(164,183
|
)
|
|||
Series A Preferred units interest in net (income) loss (5)
|
|
—
|
|
|
—
|
|
|
(42,373
|
)
|
|||
General partner interest in net (income) loss (5)
|
|
—
|
|
|
(346,538
|
)
|
|
(303,835
|
)
|
|||
Common and Class C limited partners’ interest in net income (loss) (5)
|
|
778,311
|
|
|
99,237
|
|
|
221,275
|
|
|||
Net income (loss) per common unit – basic and diluted (5)
|
|
N/A
|
|
|
$
|
0.55
|
|
|
$
|
1.30
|
|
(1)
|
Cost of product includes product purchases from affiliates (as defined in Note 1) of $254.8 million, $168.5 million, and $74.6 million for the years ended December 31, 2019, 2018, and 2017, respectively. Operation and maintenance includes charges from affiliates of $147.0 million, $115.9 million, and $82.2 million for the years ended December 31, 2019, 2018, and 2017, respectively. General and administrative includes charges from affiliates of $99.6 million, $48.8 million, and $42.4 million for the years ended December 31, 2019, 2018, and 2017, respectively. See Note 6.
|
(2)
|
Includes losses related to an incident at the DBM complex for the year ended December 31, 2017. See Note 1.
|
(3)
|
Includes affiliate amounts of $(2.0) million, $(6.7) million, and $(0.2) million for the years ended December 31, 2019, 2018, and 2017, respectively. See Note 1 and Note 13.
|
(4)
|
Includes losses associated with the interest-rate swap agreements for the years ended December 31, 2019 and 2018. See Note 13.
|
(5)
|
See Note 5 for the calculation of net income (loss) per common unit.
|
|
|
December 31,
|
||||||
thousands except number of units
|
|
2019
|
|
2018
|
||||
ASSETS
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
98,122
|
|
|
$
|
90,448
|
|
Accounts receivable, net (1)
|
|
260,748
|
|
|
221,373
|
|
||
Other current assets (2)
|
|
39,914
|
|
|
30,583
|
|
||
Total current assets
|
|
398,784
|
|
|
342,404
|
|
||
Note receivable – Anadarko
|
|
260,000
|
|
|
260,000
|
|
||
Property, plant, and equipment
|
|
|
|
|
||||
Cost
|
|
12,355,671
|
|
|
11,258,773
|
|
||
Less accumulated depreciation
|
|
3,290,740
|
|
|
2,848,420
|
|
||
Net property, plant, and equipment
|
|
9,064,931
|
|
|
8,410,353
|
|
||
Goodwill
|
|
445,800
|
|
|
445,800
|
|
||
Other intangible assets
|
|
809,391
|
|
|
841,408
|
|
||
Equity investments
|
|
1,285,717
|
|
|
1,092,088
|
|
||
Other assets (3)
|
|
78,202
|
|
|
62,792
|
|
||
Total assets
|
|
$
|
12,342,825
|
|
|
$
|
11,454,845
|
|
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accounts and imbalance payables
|
|
$
|
293,128
|
|
|
$
|
443,343
|
|
Short-term debt (4)
|
|
7,873
|
|
|
—
|
|
||
Accrued ad valorem taxes
|
|
35,160
|
|
|
36,986
|
|
||
Accrued liabilities (5)
|
|
149,639
|
|
|
127,874
|
|
||
Total current liabilities
|
|
485,800
|
|
|
608,203
|
|
||
Long-term liabilities
|
|
|
|
|
||||
Long-term debt
|
|
7,951,565
|
|
|
4,787,381
|
|
||
APCWH Note Payable (6)
|
|
—
|
|
|
427,493
|
|
||
Deferred income taxes
|
|
18,899
|
|
|
280,017
|
|
||
Asset retirement obligations
|
|
336,396
|
|
|
300,024
|
|
||
Other liabilities (7)
|
|
208,346
|
|
|
132,130
|
|
||
Total long-term liabilities
|
|
8,515,206
|
|
|
5,927,045
|
|
||
Total liabilities
|
|
9,001,006
|
|
|
6,535,248
|
|
||
Equity and partners’ capital
|
|
|
|
|
||||
Common units (318,675,578 and 152,609,285 units issued and outstanding at December 31, 2019 and 2018, respectively)
|
|
3,286,620
|
|
|
2,475,540
|
|
||
Class C units (zero and 14,372,665 units issued and outstanding at December 31, 2019 and 2018, respectively) (8)
|
|
—
|
|
|
791,410
|
|
||
General partner units (zero and 2,583,068 units issued and outstanding at December 31, 2019 and 2018, respectively) (8)
|
|
—
|
|
|
206,862
|
|
||
Net investment by Anadarko
|
|
—
|
|
|
1,388,018
|
|
||
Total partners’ capital
|
|
3,286,620
|
|
|
4,861,830
|
|
||
Noncontrolling interest
|
|
55,199
|
|
|
57,767
|
|
||
Total equity and partners’ capital
|
|
3,341,819
|
|
|
4,919,597
|
|
||
Total liabilities, equity and partners’ capital
|
|
$
|
12,342,825
|
|
|
$
|
11,454,845
|
|
(1)
|
Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $113.6 million and $72.8 million as of December 31, 2019 and 2018, respectively.
|
(2)
|
Other current assets includes affiliate amounts of $5.0 million and $3.7 million as of December 31, 2019 and 2018, respectively.
|
(3)
|
Other assets includes affiliate amounts of $60.2 million and $42.2 million as of December 31, 2019 and 2018, respectively. Other assets also includes $4.5 million and $5.3 million of NGLs line fill as of December 31, 2019 and 2018, respectively.
|
(4)
|
As of December 31, 2019, all amounts are considered affiliate. See Note 14.
|
(5)
|
Accrued liabilities includes affiliate amounts of $3.1 million and $2.2 million as of December 31, 2019 and 2018, respectively.
|
(6)
|
See Note 1 and Note 6.
|
(7)
|
Other liabilities includes affiliate amounts of $97.8 million and $47.8 million as of December 31, 2019 and 2018, respectively.
|
(8)
|
Immediately prior to the closing of the Merger (as defined in Note 1), all outstanding general partner units converted into a non-economic general partner interest in WES Operating and WES Operating common units and all outstanding Class C units converted into WES Operating common units on a one-for-one basis.
|
|
|
Partners’ Capital
|
|
|
|
|
||||||||||||||||||||||
thousands
|
|
Net
Investment
by Anadarko
|
|
Common
Units
|
|
Class C
Units
|
|
Series A Preferred Units
|
|
General
Partner
Units
|
|
Noncontrolling
Interest
|
|
Total
|
||||||||||||||
Balance at December 31, 2016
|
|
$
|
761,890
|
|
|
$
|
2,536,872
|
|
|
$
|
750,831
|
|
|
$
|
639,545
|
|
|
$
|
143,968
|
|
|
$
|
64,563
|
|
|
$
|
4,897,669
|
|
Net income (loss)
|
|
164,183
|
|
|
231,405
|
|
|
24,790
|
|
|
7,453
|
|
|
303,835
|
|
|
10,735
|
|
|
742,401
|
|
|||||||
Above-market component of swap agreements with Anadarko (1)
|
|
—
|
|
|
58,551
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
58,551
|
|
|||||||
Conversion of Series A Preferred units into common units (2)
|
|
—
|
|
|
686,936
|
|
|
—
|
|
|
(686,936
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Amortization of beneficial conversion feature of Class C units and Series A Preferred units
|
|
—
|
|
|
(66,718
|
)
|
|
4,419
|
|
|
62,299
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Distributions to Chipeta noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13,569
|
)
|
|
(13,569
|
)
|
|||||||
Distributions to WES Operating unitholders
|
|
—
|
|
|
(510,228
|
)
|
|
—
|
|
|
(22,361
|
)
|
|
(268,711
|
)
|
|
—
|
|
|
(801,300
|
)
|
|||||||
Acquisitions from affiliates
|
|
(1,263
|
)
|
|
1,263
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Revision to Deferred purchase price obligation – Anadarko (3)
|
|
—
|
|
|
4,165
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,165
|
|
|||||||
Contributions of equity-based compensation from Anadarko
|
|
—
|
|
|
4,473
|
|
|
—
|
|
|
—
|
|
|
90
|
|
|
—
|
|
|
4,563
|
|
|||||||
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
126,866
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
126,866
|
|
|||||||
Net contributions from (distributions to) Anadarko of other assets
|
|
—
|
|
|
3,139
|
|
|
—
|
|
|
—
|
|
|
50
|
|
|
—
|
|
|
3,189
|
|
|||||||
Adjustments of net deferred tax liabilities
|
|
(1,505
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,505
|
)
|
|||||||
Other
|
|
—
|
|
|
152
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
152
|
|
|||||||
Balance at December 31, 2017
|
|
$
|
1,050,171
|
|
|
$
|
2,950,010
|
|
|
$
|
780,040
|
|
|
$
|
—
|
|
|
$
|
179,232
|
|
|
$
|
61,729
|
|
|
$
|
5,021,182
|
|
Cumulative effect of accounting change (4)
|
|
629
|
|
|
(41,108
|
)
|
|
(3,533
|
)
|
|
—
|
|
|
(696
|
)
|
|
958
|
|
|
(43,750
|
)
|
|||||||
Net income (loss)
|
|
182,142
|
|
|
87,581
|
|
|
11,656
|
|
|
—
|
|
|
346,538
|
|
|
8,609
|
|
|
636,526
|
|
|||||||
Above-market component of swap agreements with Anadarko (1)
|
|
—
|
|
|
51,618
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
51,618
|
|
|||||||
Amortization of beneficial conversion feature of Class C units
|
|
—
|
|
|
(3,247
|
)
|
|
3,247
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Distributions to Chipeta noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13,529
|
)
|
|
(13,529
|
)
|
|||||||
Distributions to WES Operating unitholders
|
|
—
|
|
|
(575,323
|
)
|
|
—
|
|
|
—
|
|
|
(318,326
|
)
|
|
—
|
|
|
(893,649
|
)
|
|||||||
Contributions of equity-based compensation from Anadarko
|
|
—
|
|
|
5,613
|
|
|
—
|
|
|
—
|
|
|
114
|
|
|
—
|
|
|
5,727
|
|
|||||||
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
97,755
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
97,755
|
|
|||||||
Net contributions from (distributions to) Anadarko of other assets
|
|
58,835
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
58,835
|
|
|||||||
Adjustments of net deferred tax liabilities
|
|
(1,514
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,514
|
)
|
|||||||
Other
|
|
—
|
|
|
396
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
396
|
|
|||||||
Balance at December 31, 2018
|
|
$
|
1,388,018
|
|
|
$
|
2,475,540
|
|
|
$
|
791,410
|
|
|
$
|
—
|
|
|
$
|
206,862
|
|
|
$
|
57,767
|
|
|
$
|
4,919,597
|
|
Net income (loss)
|
|
29,279
|
|
|
765,678
|
|
|
10,636
|
|
|
—
|
|
|
1,997
|
|
|
7,095
|
|
|
814,685
|
|
|||||||
Cumulative impact of the Merger transactions (5)
|
|
—
|
|
|
926,236
|
|
|
(802,588
|
)
|
|
—
|
|
|
(123,648
|
)
|
|
—
|
|
|
—
|
|
|||||||
Above-market component of swap agreements with Anadarko (1)
|
|
—
|
|
|
7,407
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,407
|
|
|||||||
Amortization of beneficial conversion feature of Class C units
|
|
—
|
|
|
(542
|
)
|
|
542
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Distributions to Chipeta noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(9,663
|
)
|
|
(9,663
|
)
|
|||||||
Distributions to WES Operating unitholders
|
|
—
|
|
|
(1,039,158
|
)
|
|
—
|
|
|
—
|
|
|
(85,230
|
)
|
|
—
|
|
|
(1,124,388
|
)
|
|||||||
Acquisitions from affiliates (6)
|
|
(2,149,218
|
)
|
|
141,717
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,007,501
|
)
|
|||||||
Contributions of equity-based compensation from Occidental
|
|
—
|
|
|
13,938
|
|
|
—
|
|
|
—
|
|
|
19
|
|
|
—
|
|
|
13,957
|
|
|||||||
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
458,819
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
458,819
|
|
|||||||
Net contributions from (distributions to) Occidental of other assets
|
|
—
|
|
|
(90
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(90
|
)
|
|||||||
Adjustments of net deferred tax liabilities
|
|
273,102
|
|
|
(4,375
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
268,727
|
|
|||||||
Other
|
|
—
|
|
|
269
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
269
|
|
|||||||
Balance at December 31, 2019
|
|
$
|
—
|
|
|
$
|
3,286,620
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
55,199
|
|
|
$
|
3,341,819
|
|
(1)
|
See Note 6.
|
(2)
|
See Note 5.
|
(3)
|
See Note 3.
|
(4)
|
Includes the adoption of Revenue from Contracts with Customers (Topic 606) on January 1, 2018. See Note 1.
|
(5)
|
See Note 1.
|
(6)
|
The amount allocated to common unitholders represents a non-cash investing activity related to the assets and liabilities assumed in the AMA acquisition.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
Cash flows from operating activities
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
814,685
|
|
|
$
|
636,526
|
|
|
$
|
742,401
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
Depreciation and amortization
|
|
483,255
|
|
|
389,164
|
|
|
318,771
|
|
|||
Impairments
|
|
6,279
|
|
|
230,584
|
|
|
180,051
|
|
|||
Non-cash equity-based compensation expense
|
|
14,235
|
|
|
6,153
|
|
|
4,922
|
|
|||
Deferred income taxes
|
|
7,609
|
|
|
139,048
|
|
|
(53,138
|
)
|
|||
Accretion and amortization of long-term obligations, net
|
|
8,421
|
|
|
5,142
|
|
|
4,254
|
|
|||
Equity income, net – affiliates
|
|
(237,518
|
)
|
|
(195,469
|
)
|
|
(115,141
|
)
|
|||
Distributions from equity-investment earnings – affiliates
|
|
234,572
|
|
|
187,392
|
|
|
117,093
|
|
|||
(Gain) loss on divestiture and other, net (1)
|
|
1,406
|
|
|
(1,312
|
)
|
|
(132,388
|
)
|
|||
(Gain) loss on interest-rate swaps
|
|
125,334
|
|
|
7,972
|
|
|
—
|
|
|||
Cash paid to settle interest-rate swaps
|
|
(107,685
|
)
|
|
—
|
|
|
—
|
|
|||
Lower of cost or market inventory adjustments
|
|
236
|
|
|
752
|
|
|
145
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
|
||||||
(Increase) decrease in accounts receivable, net
|
|
(44,939
|
)
|
|
(60,460
|
)
|
|
(16,177
|
)
|
|||
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net
|
|
(29,745
|
)
|
|
44,424
|
|
|
(947
|
)
|
|||
Change in other items, net
|
|
56,044
|
|
|
(37,802
|
)
|
|
(3,048
|
)
|
|||
Net cash provided by operating activities
|
|
1,332,189
|
|
|
1,352,114
|
|
|
1,046,798
|
|
|||
Cash flows from investing activities
|
|
|
|
|
|
|
||||||
Capital expenditures
|
|
(1,188,829
|
)
|
|
(1,948,595
|
)
|
|
(1,028,319
|
)
|
|||
Contributions in aid of construction costs from affiliates
|
|
—
|
|
|
—
|
|
|
1,387
|
|
|||
Acquisitions from affiliates
|
|
(2,007,926
|
)
|
|
(254
|
)
|
|
(3,910
|
)
|
|||
Acquisitions from third parties
|
|
(93,303
|
)
|
|
(161,858
|
)
|
|
(177,798
|
)
|
|||
Investments in equity affiliates
|
|
(128,393
|
)
|
|
(133,629
|
)
|
|
(2,884
|
)
|
|||
Distributions from equity investments in excess of cumulative earnings – affiliates
|
|
30,256
|
|
|
29,585
|
|
|
31,659
|
|
|||
Proceeds from the sale of assets to third parties
|
|
342
|
|
|
3,938
|
|
|
23,564
|
|
|||
Proceeds from property insurance claims
|
|
—
|
|
|
—
|
|
|
22,977
|
|
|||
Net cash used in investing activities
|
|
(3,387,853
|
)
|
|
(2,210,813
|
)
|
|
(1,133,324
|
)
|
|||
Cash flows from financing activities
|
|
|
|
|
|
|
||||||
Borrowings, net of debt issuance costs (2)
|
|
4,169,695
|
|
|
2,671,344
|
|
|
468,803
|
|
|||
Repayments of debt (3)
|
|
(1,439,595
|
)
|
|
(1,040,000
|
)
|
|
—
|
|
|||
Settlement of the Deferred purchase price obligation – Anadarko (4)
|
|
—
|
|
|
—
|
|
|
(37,346
|
)
|
|||
Increase (decrease) in outstanding checks
|
|
1,571
|
|
|
(3,206
|
)
|
|
5,593
|
|
|||
Proceeds from the issuance of common units, net of offering expenses
|
|
—
|
|
|
—
|
|
|
(183
|
)
|
|||
Distributions to WES Operating unitholders (5)
|
|
(1,124,388
|
)
|
|
(893,649
|
)
|
|
(801,300
|
)
|
|||
Distributions to Chipeta noncontrolling interest owner
|
|
(9,663
|
)
|
|
(13,529
|
)
|
|
(13,569
|
)
|
|||
Net contributions from (distributions to) Anadarko
|
|
458,819
|
|
|
97,755
|
|
|
126,866
|
|
|||
Above-market component of swap agreements with Anadarko (5)
|
|
7,407
|
|
|
51,618
|
|
|
58,551
|
|
|||
Finance lease payments – affiliates
|
|
(508
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash provided by (used in) financing activities
|
|
2,063,338
|
|
|
870,333
|
|
|
(192,585
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
|
7,674
|
|
|
11,634
|
|
|
(279,111
|
)
|
|||
Cash and cash equivalents at beginning of period
|
|
90,448
|
|
|
78,814
|
|
|
357,925
|
|
|||
Cash and cash equivalents at end of period
|
|
$
|
98,122
|
|
|
$
|
90,448
|
|
|
$
|
78,814
|
|
Supplemental disclosures
|
|
|
|
|
|
|
||||||
Accretion expense and revisions to the Deferred purchase price obligation – Anadarko (4)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(4,094
|
)
|
Net distributions to (contributions from) Anadarko of other assets
|
|
90
|
|
|
(58,835
|
)
|
|
(3,189
|
)
|
|||
Interest paid, net of capitalized interest
|
|
293,561
|
|
|
139,482
|
|
|
135,079
|
|
|||
Taxes paid (reimbursements received)
|
|
96
|
|
|
2,408
|
|
|
1,194
|
|
|||
Accrued capital expenditures
|
|
140,954
|
|
|
274,632
|
|
|
312,720
|
|
|||
Fair value of properties and equipment from non-cash third-party transactions (4)
|
|
—
|
|
|
—
|
|
|
551,453
|
|
(1)
|
Includes losses related to an incident at the DBM complex for the year ended December 31, 2017. See Note 1.
|
(2)
|
For the years ended December 31, 2019 and 2018, includes $11.0 million and $321.8 million of borrowings, respectively, under the APCWH Note Payable.
|
(3)
|
For the year ended December 31, 2019, includes a $439.6 million repayment to settle the APCWH Note Payable. See Note 6.
|
(4)
|
See Note 3.
|
(5)
|
See Note 6.
|
|
|
Wholly
Owned and
Operated
|
|
Operated
Interests
|
|
Non-Operated
Interests
|
|
Equity
Interests
|
||||
Gathering systems (1)
|
|
17
|
|
|
2
|
|
|
3
|
|
|
2
|
|
Treating facilities
|
|
37
|
|
|
3
|
|
|
—
|
|
|
3
|
|
Natural-gas processing plants/trains
|
|
25
|
|
|
3
|
|
|
—
|
|
|
5
|
|
NGLs pipelines
|
|
2
|
|
|
—
|
|
|
—
|
|
|
4
|
|
Natural-gas pipelines
|
|
5
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Crude-oil pipelines
|
|
3
|
|
|
1
|
|
|
—
|
|
|
3
|
|
(1)
|
Includes the DBM water systems.
|
•
|
Exchange Agreement. Western Gas Resources, Inc. (“WGRI”), the general partner, and the Partnership entered into a partnership interests exchange agreement (the “Exchange Agreement”), pursuant to which the Partnership canceled the non-economic general partner interest in the Partnership and simultaneously issued a 2.0% general partner interest to the general partner in exchange for which WGRI transferred 9,060,641 common units to the Partnership, which immediately canceled such units on receipt.
|
•
|
Services, Secondment, and Employee Transfer Agreement. Occidental, Anadarko, and WES Operating GP entered into an amended and restated Services, Secondment, and Employee Transfer Agreement (the “Services Agreement”), pursuant to which Occidental, Anadarko, and their subsidiaries will (i) second certain personnel employed by Occidental to WES Operating GP, in exchange for which WES Operating GP will pay a monthly secondment and shared services fee to Occidental equivalent to the direct cost of the seconded employees and (ii) continue to provide certain administrative and operational services to the Partnership for up to a two-year transition period. The Services Agreement also includes provisions governing the transfer of certain employees to the Partnership and the assumption by the Partnership of liabilities relating to those employees at the time of their transfer. In January 2020, pursuant to the Services Agreement, Occidental made a one-time cash contribution of $20.0 million to the Partnership for anticipated transition costs required to establish stand-alone human resources and information technology functions.
|
•
|
RCF amendment. WES Operating entered into an amendment to its $2.0 billion senior unsecured revolving credit facility (“RCF”) to, among other things, (i) effective on February 14, 2020, exercise the final one-year extension option to extend the maturity date of the RCF to February 14, 2025, for the extending lenders, and (ii) modify the change of control definition to provide, among other things, that, subject to certain conditions, if the limited partners of the Partnership elect to remove the general partner as the general partner of the Partnership in accordance with the terms of the partnership agreement, then such removal will not constitute a change of control under the RCF.
|
•
|
Term loan facility amendment. WES Operating entered into an amendment of its $3.0 billion senior unsecured credit facility (“Term loan facility”) to, among other things, modify the change of control definition to provide, among other things, that, subject to certain conditions, if the limited partners of the Partnership elect to remove the general partner as the general partner of the Partnership in accordance with the terms of the partnership agreement, then such removal will not constitute a change of control under the Term loan facility.
|
•
|
Termination of debt-indemnification agreements. WES Operating GP and certain wholly owned subsidiaries of Occidental mutually terminated the debt-indemnification agreements related to indebtedness incurred by WES Operating.
|
•
|
Termination of omnibus agreements. The Partnership and WES Operating entered into agreements with Occidental to terminate the WES and WES Operating omnibus agreements. See Note 6.
|
|
|
Percentage Interest
|
|
Full consolidation
|
|
|
|
Chipeta (1)
|
|
75.00
|
%
|
Proportionate consolidation (2)
|
|
|
|
Springfield system
|
|
50.10
|
%
|
Marcellus Interest systems
|
|
33.75
|
%
|
Equity investments (3)
|
|
|
|
Mi Vida
|
|
50.00
|
%
|
Ranch Westex
|
|
50.00
|
%
|
FRP
|
|
33.33
|
%
|
Red Bluff Express
|
|
30.00
|
%
|
Mont Belvieu JV
|
|
25.00
|
%
|
Rendezvous
|
|
22.00
|
%
|
TEP
|
|
20.00
|
%
|
TEG
|
|
20.00
|
%
|
Whitethorn LLC
|
|
20.00
|
%
|
Saddlehorn
|
|
20.00
|
%
|
Cactus II
|
|
15.00
|
%
|
Panola
|
|
15.00
|
%
|
Fort Union
|
|
14.81
|
%
|
White Cliffs
|
|
10.00
|
%
|
(1)
|
The 25% third-party interest in Chipeta Processing LLC (“Chipeta”) is reflected within noncontrolling interests in the consolidated financial statements, in addition to the noncontrolling interests noted below.
|
(2)
|
The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues, and expenses attributable to these assets.
|
(3)
|
Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method of accounting. “Equity-investment throughput” refers to the Partnership’s share of average throughput for these investments.
|
|
|
Year Ended December 31,
|
||||||
thousands
|
|
2019
|
|
2018
|
||||
Revenue from customers
|
|
|
|
|
||||
Service revenues – fee based
|
|
$
|
2,388,191
|
|
|
$
|
1,905,728
|
|
Service revenues – product based
|
|
70,127
|
|
|
88,785
|
|
||
Product sales
|
|
287,055
|
|
|
310,895
|
|
||
Total revenue from customers
|
|
2,745,373
|
|
|
2,305,408
|
|
||
Revenue from other than customers
|
|
|
|
|
||||
Net gains (losses) on commodity-price swap agreements
|
|
(667
|
)
|
|
(7,875
|
)
|
||
Other
|
|
1,468
|
|
|
2,125
|
|
||
Total revenues and other
|
|
$
|
2,746,174
|
|
|
$
|
2,299,658
|
|
thousands
|
|
|
||
Balance at December 31, 2018
|
|
$
|
47,621
|
|
Amounts transferred to Accounts receivable, net that were included in the contract assets balance at the beginning of the period
|
|
(4,841
|
)
|
|
Additional estimated revenues recognized
|
|
14,698
|
|
|
Cumulative catch-up adjustment for change in estimated consideration due to an annual cost-of-service rate update
|
|
9,879
|
|
|
Balance at December 31, 2019
|
|
$
|
67,357
|
|
|
|
|
||
Contract assets at December 31, 2019
|
|
|
||
Other current assets
|
|
$
|
7,129
|
|
Other assets
|
|
60,228
|
|
|
Total contract assets from contracts with customers
|
|
$
|
67,357
|
|
thousands
|
|
|
||
Balance at December 31, 2018
|
|
$
|
145,624
|
|
Cash received or receivable, excluding revenues recognized during the period
|
|
75,166
|
|
|
Revenues recognized that were included in the contract liability balance at the beginning of the period
|
|
(12,110
|
)
|
|
Cumulative catch-up adjustment for change in estimated consideration due to an annual cost-of-service rate update
|
|
13,594
|
|
|
Balance at December 31, 2019
|
|
$
|
222,274
|
|
|
|
|
||
Contract liabilities at December 31, 2019
|
|
|
||
Accrued liabilities
|
|
$
|
19,659
|
|
Other liabilities
|
|
202,615
|
|
|
Total contract liabilities from contracts with customers
|
|
$
|
222,274
|
|
thousands
|
|
|
||
2020
|
|
$
|
736,055
|
|
2021
|
|
776,068
|
|
|
2022
|
|
1,030,527
|
|
|
2023
|
|
973,799
|
|
|
2024
|
|
943,514
|
|
|
Thereafter
|
|
3,534,725
|
|
|
Total
|
|
$
|
7,994,688
|
|
•
|
Wattenberg processing plant. The Wattenberg processing plant consists of a cryogenic train (with capacity of 190 million cubic feet per day (“MMcf/d”)) and a refrigeration train (with capacity of 80 MMcf/d) located in Adams County, Colorado, now part of the DJ Basin complex.
|
•
|
Wamsutter pipeline. The Wamsutter pipeline is a crude-oil gathering pipeline located in Sweetwater County, Wyoming and delivers crude oil into MPLX LP’s SLC Core Pipeline System (formerly referred to as the Wamsutter Pipeline System).
|
•
|
DJ Basin oil system. The DJ Basin oil system consists of (i) a crude-oil gathering system, (ii) a centralized oil stabilization facility (“COSF”), and (iii) a 12-mile crude-oil pipeline, located in Weld County, Colorado. The COSF consists of Trains I through VI with total capacity of 155 thousand barrels per day (“MBbls/d”) and two storage tanks with total capacity of 500,000 barrels. Train VI commenced operations in 2018. The pipeline connects the COSF to Tampa Rail.
|
•
|
DBM oil system. The DBM oil system consists of (i) a crude-oil gathering system, (ii) three central production facilities (“CPFs”), which include ten processing trains with total capacity of 75 MBbls/d, (iii) three storage tanks with total capacity of 30,000 barrels, (iv) a 14-mile crude-oil pipeline, and (v) two regional oil treating facilities (“ROTFs”), which include four trains with total capacity of 120 MBbls/d, located in Reeves and Loving Counties, Texas. The ROTFs commenced operations in 2018. The pipeline transports crude oil from the DBM oil system and one third-party CPF into Plains All American Pipeline.
|
•
|
APC water systems. The APC water systems consist of five produced-water disposal systems with total capacity of 565 MBbls/d, located in Reeves, Loving, and Ward Counties, Texas, which are now part of the DBM water systems. One produced-water disposal system commenced operations in 2017 and the other four commenced operations in 2018.
|
•
|
A 20% interest in Saddlehorn. Saddlehorn owns (i) a crude-oil and condensate pipeline (excluding pipeline capacity leased by Saddlehorn) that originates in Laramie County, Wyoming, and terminates in Cushing, Oklahoma, and (ii) four storage tanks with total capacity of 300,000 barrels. The Saddlehorn interest is accounted for under the equity method of accounting and the pipeline is operated by a third party.
|
•
|
A 15% interest in Panola. Panola owns a 248-mile NGLs pipeline that originates in Panola County, Texas, and terminates in Mont Belvieu, Texas. The Panola interest is accounted for under the equity method of accounting and the pipeline is operated by a third party.
|
•
|
A 50% interest in Mi Vida. Mi Vida owns a cryogenic gas processing plant (with capacity of 200 MMcf/d) located in Ward County, Texas. The interest in Mi Vida is accounted for under the equity method of accounting and the processing plant is operated by a third party.
|
•
|
A 50% interest in Ranch Westex. Ranch Westex owns a processing plant consisting of a cryogenic train (with capacity of 100 MMcf/d) and a refrigeration train (with capacity of 25 MMcf/d), located in Ward County, Texas. The interest in Ranch Westex is accounted for under the equity method of accounting and the processing plant is operated by a third party.
|
thousands except per-unit amounts
Quarters Ended |
|
Total Quarterly
Per-unit Distribution |
|
Total Quarterly
Cash Distribution |
|
Distribution
Date |
|||||
2017 (1)
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.49125
|
|
|
$
|
107,549
|
|
|
May 2017
|
|
June 30
|
|
0.52750
|
|
|
115,487
|
|
|
August 2017
|
|||
September 30
|
|
0.53750
|
|
|
117,677
|
|
|
November 2017
|
|||
December 31
|
|
0.54875
|
|
|
120,140
|
|
|
February 2018
|
|||
2018 (1)
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.56875
|
|
|
$
|
124,518
|
|
|
May 2018
|
|
June 30
|
|
0.58250
|
|
|
127,531
|
|
|
August 2018
|
|||
September 30
|
|
0.59500
|
|
|
130,268
|
|
|
November 2018
|
|||
December 31
|
|
0.60250
|
|
|
131,910
|
|
|
February 2019
|
|||
2019
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.61000
|
|
|
$
|
276,324
|
|
|
May 2019
|
|
June 30
|
|
0.61800
|
|
|
279,959
|
|
|
August 2019
|
|||
September 30
|
|
0.62000
|
|
|
280,880
|
|
|
November 2019
|
|||
December 31 (2)
|
|
0.62200
|
|
|
281,786
|
|
|
February 2020
|
(1)
|
The 2017 and 2018 distributions were declared and paid prior to the closing of the Merger.
|
(2)
|
The Board of Directors declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2019 of $0.62200 per unit, or $281.8 million in aggregate. The cash distribution was paid on February 13, 2020, to unitholders of record at the close of business on January 31, 2020, including the general partner units that were issued on December 31, 2019 (see Note 1).
|
thousands except per-unit amounts
Quarters Ended |
|
Total Quarterly
Per-unit Distribution |
|
Total Quarterly
Cash Distribution |
|
Distribution
Date |
|||||
2017
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.875
|
|
|
$
|
188,753
|
|
|
May 2017
|
|
June 30
|
|
0.890
|
|
|
207,491
|
|
|
August 2017
|
|||
September 30
|
|
0.905
|
|
|
212,038
|
|
|
November 2017
|
|||
December 31
|
|
0.920
|
|
|
216,586
|
|
|
February 2018
|
|||
2018
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.935
|
|
|
$
|
221,133
|
|
|
May 2018
|
|
June 30
|
|
0.950
|
|
|
225,691
|
|
|
August 2018
|
|||
September 30
|
|
0.965
|
|
|
230,239
|
|
|
November 2018
|
|||
December 31
|
|
0.980
|
|
|
234,787
|
|
|
February 2019
|
Partnership common units outstanding prior to the Merger
|
|
|
218,937,797
|
|
|
WES Operating common units outstanding prior to the Merger
|
|
152,609,285
|
|
|
|
WES Operating Class C units outstanding prior to the Merger
|
|
14,681,388
|
|
|
|
Less: WES Operating common units owned by the Partnership
|
|
(50,132,046
|
)
|
|
|
WES Operating common units subject to conversion into Partnership common units
|
|
117,158,627
|
|
|
|
Exchange ratio per unit
|
|
1.525
|
|
|
|
Partnership common units issued for WES Operating common units (1)
|
|
|
178,692,081
|
|
|
WES Operating common units issued as part of the AMA acquisition
|
|
45,760,201
|
|
|
|
Less: WES Operating common units retained by a subsidiary of Anadarko
|
|
(6,375,284
|
)
|
|
|
WES Operating acquisition common units subject to conversion into Partnership common units
|
|
39,384,917
|
|
|
|
Conversion ratio per unit
|
|
1.4056
|
|
|
|
Partnership common units issued for WES Operating acquisition common units
|
|
|
55,360,984
|
|
|
Partnership common units outstanding at February 28, 2019
|
|
|
452,990,862
|
|
(1)
|
Total Partnership units issued at Merger completion exceeds the calculation of such units using the exchange ratio due to the rounding convention described in the Merger Agreement.
|
|
|
Common
Units
|
|
Class C
Units
|
|
General
Partner
Units
|
|
Total
|
||||
Balance at December 31, 2017
|
|
152,602,105
|
|
|
13,243,883
|
|
|
2,583,068
|
|
|
168,429,056
|
|
PIK Class C units
|
|
—
|
|
|
1,128,782
|
|
|
—
|
|
|
1,128,782
|
|
Vesting of Long-Term Incentive Plan Awards
|
|
7,180
|
|
|
—
|
|
|
—
|
|
|
7,180
|
|
Balance at December 31, 2018
|
|
152,609,285
|
|
|
14,372,665
|
|
|
2,583,068
|
|
|
169,565,018
|
|
PIK Class C units
|
|
—
|
|
|
308,723
|
|
|
—
|
|
|
308,723
|
|
Conversion of Class C units
|
|
14,681,388
|
|
|
(14,681,388
|
)
|
|
—
|
|
|
—
|
|
IDR and General partner unit conversion
|
|
105,624,704
|
|
|
—
|
|
|
(2,583,068
|
)
|
|
103,041,636
|
|
Units issued as part of the AMA acquisition
|
|
45,760,201
|
|
|
—
|
|
|
—
|
|
|
45,760,201
|
|
Balance at December 31, 2019 (1)
|
|
318,675,578
|
|
|
—
|
|
|
—
|
|
|
318,675,578
|
|
(1)
|
All WES Operating common units that converted into the Partnership’s common units at closing of the Merger were canceled and an equivalent amount of the canceled WES Operating common units were issued to the Partnership. See Note 1 for further details on the units issued and converted in connection with the closing of the Merger.
|
|
|
Year Ended December 31,
|
||||||
thousands except per-unit amounts
|
|
2018
|
|
2017
|
||||
Net income (loss) attributable to Western Midstream Operating, LP
|
|
$
|
627,917
|
|
|
$
|
731,666
|
|
Pre-acquisition net (income) loss allocated to Anadarko
|
|
(182,142
|
)
|
|
(164,183
|
)
|
||
Series A Preferred units interest in net (income) loss (1)
|
|
—
|
|
|
(42,373
|
)
|
||
General partner interest in net (income) loss
|
|
(346,538
|
)
|
|
(303,835
|
)
|
||
Common and Class C limited partners’ interest in net income (loss)
|
|
$
|
99,237
|
|
|
$
|
221,275
|
|
Net income (loss) allocable to common units (1)
|
|
$
|
84,334
|
|
|
$
|
192,066
|
|
Net income (loss) allocable to Class C units (1)
|
|
14,903
|
|
|
29,209
|
|
||
Common and Class C limited partners’ interest in net income (loss)
|
|
$
|
99,237
|
|
|
$
|
221,275
|
|
Net income (loss) per unit
|
|
|
|
|
||||
Common units – basic and diluted (2)
|
|
$
|
0.55
|
|
|
$
|
1.30
|
|
Weighted-average units outstanding
|
|
|
|
|
||||
Common units – basic and diluted
|
|
152,606
|
|
|
147,194
|
|
||
Excluded due to anti-dilutive effect:
|
|
|
|
|
||||
Class C units (2)
|
|
13,795
|
|
|
12,776
|
|
||
Series A Preferred units assuming conversion to common units (2)
|
|
—
|
|
|
5,406
|
|
(1)
|
Adjusted to reflect amortization of the beneficial conversion features.
|
(2)
|
The impact of Class C units would be anti-dilutive for the periods presented and the conversion of Series A Preferred units would be anti-dilutive for the year ended December 31, 2017. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a one-for-one basis.
|
|
|
DJ Basin Complex
|
||||||||||
per barrel except natural gas
|
|
2017 - 2018 Swap Prices
|
|
2017 Market Prices (1)
|
|
2018 Market Prices (1)
|
||||||
Ethane
|
|
$
|
18.41
|
|
|
$
|
5.09
|
|
|
$
|
5.41
|
|
Propane
|
|
47.08
|
|
|
18.85
|
|
|
28.72
|
|
|||
Isobutane
|
|
62.09
|
|
|
26.83
|
|
|
32.92
|
|
|||
Normal butane
|
|
54.62
|
|
|
26.20
|
|
|
32.71
|
|
|||
Natural gasoline
|
|
72.88
|
|
|
41.84
|
|
|
48.04
|
|
|||
Condensate
|
|
76.47
|
|
|
45.40
|
|
|
49.36
|
|
|||
Natural gas (per MMBtu)
|
|
5.96
|
|
|
3.05
|
|
|
2.21
|
|
|
|
MGR Assets
|
||||||||||
per barrel except natural gas
|
|
2017 - 2018 Swap Prices
|
|
2017 Market Prices (1)
|
|
2018 Market Prices (1)
|
||||||
Ethane
|
|
$
|
23.11
|
|
|
$
|
4.08
|
|
|
$
|
2.52
|
|
Propane
|
|
52.90
|
|
|
19.24
|
|
|
25.83
|
|
|||
Isobutane
|
|
73.89
|
|
|
25.79
|
|
|
30.03
|
|
|||
Normal butane
|
|
64.93
|
|
|
25.16
|
|
|
29.82
|
|
|||
Natural gasoline
|
|
81.68
|
|
|
45.01
|
|
|
47.25
|
|
|||
Condensate
|
|
81.68
|
|
|
53.55
|
|
|
56.76
|
|
|||
Natural gas (per MMBtu)
|
|
4.87
|
|
|
3.05
|
|
|
2.21
|
|
(1)
|
Represents the New York Mercantile Exchange forward strip price as of December 1, 2016 and December 20, 2017, for the 2017 Market Prices and 2018 Market Prices, respectively, adjusted for product specification, location, basis, and, in the case of NGLs, transportation and fractionation costs.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
General and administrative expenses
|
|
$
|
604
|
|
|
$
|
269
|
|
|
$
|
263
|
|
Public company expenses
|
|
4,089
|
|
|
2,895
|
|
|
1,821
|
|
|||
Total reimbursement
|
|
$
|
4,693
|
|
|
$
|
3,164
|
|
|
$
|
2,084
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
General and administrative expenses
|
|
$
|
84,039
|
|
|
$
|
35,077
|
|
|
$
|
31,733
|
|
Public company expenses
|
|
4,065
|
|
|
15,409
|
|
|
9,379
|
|
|||
Total reimbursement
|
|
$
|
88,104
|
|
|
$
|
50,486
|
|
|
$
|
41,112
|
|
|
|
2019
|
|
2018
|
|
2017
|
|||||||||||||||
|
|
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
|
|
$
|
35.08
|
|
|
7,128
|
|
|
$
|
43.39
|
|
|
5,763
|
|
|
$
|
39.78
|
|
|
5,658
|
|
Granted
|
|
29.75
|
|
|
25,212
|
|
|
35.08
|
|
|
7,128
|
|
|
43.39
|
|
|
5,763
|
|
|||
Vested
|
|
31.62
|
|
|
(44,572
|
)
|
|
43.39
|
|
|
(5,763
|
)
|
|
39.78
|
|
|
(5,658
|
)
|
|||
Converted (1)
|
|
33.46
|
|
|
12,232
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Phantom units outstanding at end of year
|
|
—
|
|
|
—
|
|
|
35.08
|
|
|
7,128
|
|
|
43.39
|
|
|
5,763
|
|
(1)
|
At closing of the Merger, WES Operating phantom units awarded under the Western Gas Partners, LP 2017 Long-Term Incentive Plan converted into phantom units of the Partnership under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan.
|
|
|
2019
|
|
2018
|
|
2017
|
|||||||||||||||
|
|
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
|
|
$
|
49.88
|
|
|
8,020
|
|
|
$
|
55.73
|
|
|
7,180
|
|
|
$
|
49.30
|
|
|
7,304
|
|
Granted
|
|
—
|
|
|
—
|
|
|
49.88
|
|
|
8,020
|
|
|
55.73
|
|
|
7,180
|
|
|||
Vested
|
|
—
|
|
|
—
|
|
|
55.73
|
|
|
(7,180
|
)
|
|
49.30
|
|
|
(7,304
|
)
|
|||
Converted (1)
|
|
49.88
|
|
|
(8,020
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Phantom units outstanding at end of year
|
|
—
|
|
|
—
|
|
|
49.88
|
|
|
8,020
|
|
|
55.73
|
|
|
7,180
|
|
(1)
|
At closing of the Merger, WES Operating phantom units awarded under the Western Gas Partners, LP 2017 Long-Term Incentive Plan converted into phantom units of the Partnership under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
Cash consideration paid
|
|
$
|
(425
|
)
|
|
$
|
(254
|
)
|
|
$
|
(3,910
|
)
|
Net carrying value
|
|
335
|
|
|
59,089
|
|
|
5,283
|
|
|||
Partners’ capital adjustment
|
|
$
|
(90
|
)
|
|
$
|
58,835
|
|
|
$
|
1,373
|
|
|
|
Year ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
Revenues and other (1)
|
|
$
|
1,607,396
|
|
|
$
|
1,353,711
|
|
|
$
|
1,539,105
|
|
Equity income, net – affiliates (1)
|
|
237,518
|
|
|
195,469
|
|
|
115,141
|
|
|||
Operating expenses
|
|
|
|
|
|
|
||||||
Cost of product (1)
|
|
254,771
|
|
|
168,535
|
|
|
74,560
|
|
|||
Operation and maintenance (1)
|
|
146,990
|
|
|
115,948
|
|
|
82,249
|
|
|||
General and administrative (2)
|
|
101,485
|
|
|
49,672
|
|
|
43,221
|
|
|||
Total operating expenses
|
|
503,246
|
|
|
334,155
|
|
|
200,030
|
|
|||
Interest income (3)
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense (4)
|
|
1,970
|
|
|
6,746
|
|
|
224
|
|
|||
APCWH Note Payable borrowings
|
|
11,000
|
|
|
321,780
|
|
|
98,813
|
|
|||
Repayment of APCWH Note Payable
|
|
439,595
|
|
|
—
|
|
|
—
|
|
|||
Settlement of the Deferred purchase price obligation – Anadarko (5)
|
|
—
|
|
|
—
|
|
|
(37,346
|
)
|
|||
Distributions to Partnership unitholders (6)
|
|
566,868
|
|
|
400,194
|
|
|
360,523
|
|
|||
Distributions to WES Operating unitholders (7)
|
|
19,768
|
|
|
7,583
|
|
|
7,100
|
|
|||
Above-market component of swap agreements with Anadarko
|
|
7,407
|
|
|
51,618
|
|
|
58,551
|
|
(1)
|
Represents amounts earned or incurred on and subsequent to the date of the acquisition of assets from Anadarko, and amounts earned or incurred by Anadarko on a historical basis for periods prior to the acquisition of such assets.
|
(2)
|
Represents general and administrative expense incurred on and subsequent to the date of the acquisition of assets from Anadarko, and a management services fee for expenses incurred by Anadarko for periods prior to the acquisition of such assets. These amounts include equity-based compensation expense allocated to the Partnership by Occidental (see LTIPs and Incentive Plans within this Note 6) and amounts charged by Occidental under the WES and WES Operating omnibus agreements.
|
(3)
|
Represents interest income recognized on the Anadarko note receivable.
|
(4)
|
Includes amounts related to finance leases and the APCWH Note Payable (see Note 1 and Note 13).
|
(5)
|
Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation – Anadarko (see Note 3).
|
(6)
|
Represents distributions paid to Occidental pursuant to the partnership agreement of the Partnership (see Note 4 and Note 5).
|
(7)
|
Represents distributions paid to certain subsidiaries of Occidental pursuant to WES Operating’s partnership agreement (see Note 4 and Note 5).
|
|
|
Year ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
General and administrative (1)
|
|
$
|
99,613
|
|
|
$
|
48,819
|
|
|
$
|
42,411
|
|
Distributions to WES Operating unitholders (2)
|
|
1,025,931
|
|
|
514,906
|
|
|
452,777
|
|
(1)
|
Represents general and administrative expense incurred on and subsequent to the date of the acquisition of assets from Anadarko, and a management services fee for expenses incurred by Anadarko for periods prior to the acquisition of such assets. These amounts include equity-based compensation expense allocated to WES Operating by Occidental (see LTIPs and Incentive Plans within this Note 6) and amounts charged by Occidental pursuant to the WES Operating omnibus agreement.
|
(2)
|
Represents distributions paid to the Partnership and certain subsidiaries of Occidental pursuant to WES Operating’s partnership agreement (see Note 4 and Note 5). For the year ended December 31, 2019, includes distributions to the Partnership and a subsidiary of Occidental related to the repayment of the WGP RCF (see Note 13).
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
Current income tax expense (benefit)
|
|
|
|
|
|
|
||||||
Federal income tax expense (benefit)
|
|
$
|
5,550
|
|
|
$
|
(79,264
|
)
|
|
$
|
(9,207
|
)
|
State income tax expense (benefit)
|
|
313
|
|
|
(850
|
)
|
|
2,422
|
|
|||
Total current income tax expense (benefit)
|
|
5,863
|
|
|
(80,114
|
)
|
|
(6,785
|
)
|
|||
Deferred income tax expense (benefit)
|
|
|
|
|
|
|
||||||
Federal income tax expense (benefit)
|
|
2,782
|
|
|
133,044
|
|
|
(55,835
|
)
|
|||
State income tax expense (benefit)
|
|
4,827
|
|
|
6,004
|
|
|
2,697
|
|
|||
Total deferred income tax expense (benefit)
|
|
7,609
|
|
|
139,048
|
|
|
(53,138
|
)
|
|||
Total income tax expense (benefit)
|
|
$
|
13,472
|
|
|
$
|
58,934
|
|
|
$
|
(59,923
|
)
|
|
|
Year Ended December 31,
|
||||||||||
thousands except percentages
|
|
2019
|
|
2018
|
|
2017
|
||||||
Income (loss) before income taxes
|
|
$
|
821,172
|
|
|
$
|
689,588
|
|
|
$
|
677,462
|
|
Statutory tax rate
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Tax computed at statutory rate
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Adjustments resulting from:
|
|
|
|
|
|
|
||||||
U.S. federal tax reform
|
|
—
|
|
|
—
|
|
|
(87,306
|
)
|
|||
Federal taxes on pre-acquisition income attributable to assets acquired from Anadarko
|
|
8,332
|
|
|
54,243
|
|
|
22,353
|
|
|||
State taxes on pre-acquisition income attributable to assets acquired from Anadarko (net of federal benefit)
|
|
—
|
|
|
1,745
|
|
|
164
|
|
|||
Texas margin tax expense (benefit)
|
|
5,140
|
|
|
2,946
|
|
|
4,866
|
|
|||
Income tax expense (benefit)
|
|
$
|
13,472
|
|
|
$
|
58,934
|
|
|
$
|
(59,923
|
)
|
Effective tax rate
|
|
2
|
%
|
|
9
|
%
|
|
(9
|
)%
|
|
|
December 31,
|
||||||
thousands
|
|
2019
|
|
2018
|
||||
Depreciable property
|
|
$
|
(18,642
|
)
|
|
$
|
(280,377
|
)
|
Credit carryforwards
|
|
—
|
|
|
497
|
|
||
Other intangible assets
|
|
(678
|
)
|
|
(299
|
)
|
||
Other
|
|
421
|
|
|
162
|
|
||
Net long-term deferred income tax liabilities
|
|
$
|
(18,899
|
)
|
|
$
|
(280,017
|
)
|
|
|
|
|
December 31,
|
||||||
thousands
|
|
Estimated Useful Life
|
|
2019
|
|
2018
|
||||
Land
|
|
n/a
|
|
$
|
9,495
|
|
|
$
|
5,298
|
|
Gathering systems – pipelines
|
|
30 years
|
|
5,092,004
|
|
|
4,764,099
|
|
||
Gathering systems – compressors
|
|
15 years
|
|
1,929,377
|
|
|
1,712,939
|
|
||
Processing complexes and treating facilities
|
|
25 years
|
|
3,237,801
|
|
|
2,844,337
|
|
||
Transportation pipeline and equipment
|
|
6 to 45 years
|
|
173,572
|
|
|
172,558
|
|
||
Produced-water disposal systems
|
|
20 years
|
|
754,774
|
|
|
629,946
|
|
||
Assets under construction
|
|
n/a
|
|
486,584
|
|
|
604,265
|
|
||
Other
|
|
3 to 40 years
|
|
672,064
|
|
|
525,331
|
|
||
Total property, plant, and equipment
|
|
|
|
12,355,671
|
|
|
11,258,773
|
|
||
Less accumulated depreciation
|
|
|
|
3,290,740
|
|
|
2,848,420
|
|
||
Net property, plant, and equipment
|
|
|
|
$
|
9,064,931
|
|
|
$
|
8,410,353
|
|
|
|
December 31,
|
||||||
thousands
|
|
2019
|
|
2018
|
||||
Gross carrying amount
|
|
$
|
979,863
|
|
|
$
|
979,863
|
|
Accumulated amortization
|
|
(170,472
|
)
|
|
(138,455
|
)
|
||
Other intangible assets
|
|
$
|
809,391
|
|
|
$
|
841,408
|
|
thousands
|
|
Balance at December 31, 2017
|
|
Acquisitions
|
|
Equity
income, net
|
|
Contributions (1)
|
|
Distributions
|
|
Distributions in
excess of
cumulative
earnings (2)
|
|
Balance at December 31, 2018
|
||||||||||||||
Fort Union
|
|
$
|
7,030
|
|
|
$
|
—
|
|
|
$
|
(1,433
|
)
|
|
$
|
—
|
|
|
$
|
(194
|
)
|
|
$
|
(3,144
|
)
|
|
$
|
2,259
|
|
White Cliffs
|
|
44,945
|
|
|
—
|
|
|
11,841
|
|
|
1,278
|
|
|
(11,259
|
)
|
|
(3,785
|
)
|
|
43,020
|
|
|||||||
Rendezvous
|
|
42,528
|
|
|
—
|
|
|
767
|
|
|
—
|
|
|
(2,709
|
)
|
|
(2,745
|
)
|
|
37,841
|
|
|||||||
Mont Belvieu JV
|
|
110,299
|
|
|
—
|
|
|
29,200
|
|
|
—
|
|
|
(29,239
|
)
|
|
(5,311
|
)
|
|
104,949
|
|
|||||||
TEG
|
|
15,879
|
|
|
—
|
|
|
4,290
|
|
|
3,720
|
|
|
(4,368
|
)
|
|
(163
|
)
|
|
19,358
|
|
|||||||
TEP
|
|
178,975
|
|
|
—
|
|
|
37,963
|
|
|
11,980
|
|
|
(33,552
|
)
|
|
(2,168
|
)
|
|
193,198
|
|
|||||||
FRP
|
|
166,555
|
|
|
—
|
|
|
23,308
|
|
|
14,980
|
|
|
(23,481
|
)
|
|
(4,926
|
)
|
|
176,436
|
|
|||||||
Whitethorn LLC
|
|
—
|
|
|
150,563
|
|
|
47,088
|
|
|
7,069
|
|
|
(39,497
|
)
|
|
(3,365
|
)
|
|
161,858
|
|
|||||||
Cactus II
|
|
—
|
|
|
12,052
|
|
|
—
|
|
|
94,308
|
|
|
—
|
|
|
—
|
|
|
106,360
|
|
|||||||
Saddlehorn
|
|
109,227
|
|
|
—
|
|
|
15,833
|
|
|
294
|
|
|
(16,017
|
)
|
|
(830
|
)
|
|
108,507
|
|
|||||||
Panola
|
|
23,625
|
|
|
—
|
|
|
2,200
|
|
|
—
|
|
|
(2,200
|
)
|
|
(856
|
)
|
|
22,769
|
|
|||||||
Mi Vida
|
|
64,988
|
|
|
—
|
|
|
13,734
|
|
|
—
|
|
|
(14,000
|
)
|
|
(91
|
)
|
|
64,631
|
|
|||||||
Ranch Westex
|
|
53,301
|
|
|
—
|
|
|
10,678
|
|
|
—
|
|
|
(10,876
|
)
|
|
(2,201
|
)
|
|
50,902
|
|
|||||||
Total
|
|
$
|
817,352
|
|
|
$
|
162,615
|
|
|
$
|
195,469
|
|
|
$
|
133,629
|
|
|
$
|
(187,392
|
)
|
|
$
|
(29,585
|
)
|
|
$
|
1,092,088
|
|
thousands
|
|
Balance at December 31, 2018
|
|
Acquisitions
|
|
Equity
income, net
|
|
Contributions (1)
|
|
Distributions
|
|
Distributions in
excess of
cumulative
earnings (2)
|
|
Balance at December 31, 2019
|
||||||||||||||
Fort Union
|
|
$
|
2,259
|
|
|
$
|
—
|
|
|
$
|
(2,232
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(637
|
)
|
|
$
|
(610
|
)
|
White Cliffs
|
|
43,020
|
|
|
—
|
|
|
9,500
|
|
|
5,414
|
|
|
(8,918
|
)
|
|
(3,139
|
)
|
|
45,877
|
|
|||||||
Rendezvous
|
|
37,841
|
|
|
—
|
|
|
769
|
|
|
—
|
|
|
(2,710
|
)
|
|
(2,936
|
)
|
|
32,964
|
|
|||||||
Mont Belvieu JV
|
|
104,949
|
|
|
—
|
|
|
28,412
|
|
|
—
|
|
|
(28,451
|
)
|
|
(1,874
|
)
|
|
103,036
|
|
|||||||
TEG
|
|
19,358
|
|
|
—
|
|
|
4,088
|
|
|
—
|
|
|
(4,110
|
)
|
|
(1,137
|
)
|
|
18,199
|
|
|||||||
TEP
|
|
193,198
|
|
|
—
|
|
|
30,871
|
|
|
12,220
|
|
|
(32,733
|
)
|
|
—
|
|
|
203,556
|
|
|||||||
FRP
|
|
176,436
|
|
|
—
|
|
|
32,617
|
|
|
30,175
|
|
|
(31,446
|
)
|
|
—
|
|
|
207,782
|
|
|||||||
Whitethorn LLC
|
|
161,858
|
|
|
—
|
|
|
74,548
|
|
|
10,332
|
|
|
(74,856
|
)
|
|
(10,217
|
)
|
|
161,665
|
|
|||||||
Cactus II
|
|
106,360
|
|
|
—
|
|
|
10,755
|
|
|
56,252
|
|
|
(1,202
|
)
|
|
—
|
|
|
172,165
|
|
|||||||
Saddlehorn
|
|
108,507
|
|
|
—
|
|
|
25,524
|
|
|
3,550
|
|
|
(24,726
|
)
|
|
—
|
|
|
112,855
|
|
|||||||
Panola
|
|
22,769
|
|
|
—
|
|
|
2,136
|
|
|
—
|
|
|
(2,137
|
)
|
|
(985
|
)
|
|
21,783
|
|
|||||||
Mi Vida
|
|
64,631
|
|
|
—
|
|
|
10,655
|
|
|
—
|
|
|
(12,077
|
)
|
|
(5,402
|
)
|
|
57,807
|
|
|||||||
Ranch Westex
|
|
50,902
|
|
|
—
|
|
|
6,812
|
|
|
—
|
|
|
(8,143
|
)
|
|
(2,893
|
)
|
|
46,678
|
|
|||||||
Red Bluff Express
|
|
—
|
|
|
92,546
|
|
|
3,063
|
|
|
10,450
|
|
|
(3,063
|
)
|
|
(1,036
|
)
|
|
101,960
|
|
|||||||
Total
|
|
$
|
1,092,088
|
|
|
$
|
92,546
|
|
|
$
|
237,518
|
|
|
$
|
128,393
|
|
|
$
|
(234,572
|
)
|
|
$
|
(30,256
|
)
|
|
$
|
1,285,717
|
|
(1)
|
Includes capitalized interest of $1.4 million and $3.6 million for the years ended December 31, 2018 and 2019, respectively, related to the construction of the Cactus II pipeline.
|
(2)
|
Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, are calculated on an individual-investment basis.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
Revenues
|
|
$
|
1,687,116
|
|
|
$
|
1,300,921
|
|
|
$
|
877,020
|
|
Operating income
|
|
1,107,664
|
|
|
876,910
|
|
|
542,390
|
|
|||
Net income
|
|
1,108,173
|
|
|
874,587
|
|
|
540,538
|
|
|
|
December 31,
|
||||||
thousands
|
|
2019
|
|
2018
|
||||
Current assets
|
|
$
|
433,390
|
|
|
$
|
297,143
|
|
Property, plant, and equipment, net
|
|
5,754,160
|
|
|
4,251,020
|
|
||
Other assets
|
|
175,231
|
|
|
81,769
|
|
||
Total assets
|
|
$
|
6,362,781
|
|
|
$
|
4,629,932
|
|
Current liabilities
|
|
223,171
|
|
|
$
|
101,729
|
|
|
Non-current liabilities
|
|
27,024
|
|
|
42,431
|
|
||
Equity
|
|
6,112,586
|
|
|
4,485,772
|
|
||
Total liabilities and equity
|
|
$
|
6,362,781
|
|
|
$
|
4,629,932
|
|
|
|
The Partnership
|
|
WES Operating
|
||||||||||||
|
|
December 31,
|
|
December 31,
|
||||||||||||
thousands
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
Trade receivables, net
|
|
$
|
260,458
|
|
|
$
|
221,119
|
|
|
$
|
260,694
|
|
|
$
|
221,328
|
|
Other receivables, net
|
|
54
|
|
|
45
|
|
|
54
|
|
|
45
|
|
||||
Total accounts receivable, net
|
|
$
|
260,512
|
|
|
$
|
221,164
|
|
|
$
|
260,748
|
|
|
$
|
221,373
|
|
|
|
The Partnership
|
|
WES Operating
|
||||||||||||
|
|
December 31,
|
|
December 31,
|
||||||||||||
thousands
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
NGLs inventory
|
|
$
|
906
|
|
|
$
|
1,203
|
|
|
$
|
906
|
|
|
$
|
1,203
|
|
Materials and supplies inventory
|
|
23,444
|
|
|
9,665
|
|
|
23,444
|
|
|
9,665
|
|
||||
Imbalance receivables
|
|
4,690
|
|
|
9,035
|
|
|
4,690
|
|
|
9,035
|
|
||||
Prepaid insurance
|
|
5,676
|
|
|
1,972
|
|
|
3,652
|
|
|
1,972
|
|
||||
Contract assets
|
|
7,129
|
|
|
5,399
|
|
|
7,129
|
|
|
5,399
|
|
||||
Other
|
|
93
|
|
|
4,184
|
|
|
93
|
|
|
3,309
|
|
||||
Total other current assets
|
|
$
|
41,938
|
|
|
$
|
31,458
|
|
|
$
|
39,914
|
|
|
$
|
30,583
|
|
|
|
The Partnership
|
|
WES Operating
|
||||||||||||
|
|
December 31,
|
|
December 31,
|
||||||||||||
thousands
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
Accrued interest expense
|
|
$
|
72,064
|
|
|
$
|
70,968
|
|
|
$
|
72,064
|
|
|
$
|
70,959
|
|
Short-term asset retirement obligations
|
|
22,472
|
|
|
25,938
|
|
|
22,472
|
|
|
25,938
|
|
||||
Short-term remediation and reclamation obligations
|
|
3,528
|
|
|
863
|
|
|
3,528
|
|
|
863
|
|
||||
Income taxes payable
|
|
697
|
|
|
384
|
|
|
697
|
|
|
384
|
|
||||
Contract liabilities
|
|
19,659
|
|
|
16,235
|
|
|
19,659
|
|
|
16,235
|
|
||||
Other (1)
|
|
31,373
|
|
|
14,760
|
|
|
31,219
|
|
|
13,495
|
|
||||
Total accrued liabilities
|
|
$
|
149,793
|
|
|
$
|
129,148
|
|
|
$
|
149,639
|
|
|
$
|
127,874
|
|
(1)
|
Includes amounts related to WES Operating’s interest-rate swap agreements as of December 31, 2019 and 2018 (see Note 13). Includes lease liabilities related to the implementation of ASU 2016-02, Leases (Topic 842) as of December 31, 2019 (see Note 1).
|
|
|
Year Ended December 31,
|
||||||
thousands
|
|
2019
|
|
2018
|
||||
Carrying amount of asset retirement obligations at beginning of year
|
|
$
|
325,962
|
|
|
$
|
154,571
|
|
Liabilities incurred
|
|
27,360
|
|
|
34,558
|
|
||
Liabilities settled
|
|
(17,104
|
)
|
|
(12,432
|
)
|
||
Accretion expense
|
|
13,599
|
|
|
7,909
|
|
||
Revisions in estimated liabilities
|
|
9,051
|
|
|
141,356
|
|
||
Carrying amount of asset retirement obligations at end of year
|
|
$
|
358,868
|
|
|
$
|
325,962
|
|
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||||||||||||||
thousands
|
|
Principal
|
|
Carrying
Value
|
|
Fair
Value (1)
|
|
Principal
|
|
Carrying
Value
|
|
Fair
Value (1)
|
||||||||||||
Short-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
WGP RCF
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
28,000
|
|
|
$
|
28,000
|
|
|
$
|
28,000
|
|
Finance lease liabilities (2)
|
|
7,873
|
|
|
7,873
|
|
|
7,873
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total short-term debt
|
|
$
|
7,873
|
|
|
$
|
7,873
|
|
|
$
|
7,873
|
|
|
$
|
28,000
|
|
|
$
|
28,000
|
|
|
$
|
28,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
5.375% Senior Notes due 2021
|
|
$
|
500,000
|
|
|
$
|
498,168
|
|
|
$
|
515,042
|
|
|
$
|
500,000
|
|
|
$
|
496,959
|
|
|
$
|
515,990
|
|
4.000% Senior Notes due 2022
|
|
670,000
|
|
|
669,322
|
|
|
689,784
|
|
|
670,000
|
|
|
669,078
|
|
|
662,109
|
|
||||||
3.950% Senior Notes due 2025
|
|
500,000
|
|
|
493,830
|
|
|
504,968
|
|
|
500,000
|
|
|
492,837
|
|
|
466,135
|
|
||||||
4.650% Senior Notes due 2026
|
|
500,000
|
|
|
496,197
|
|
|
513,393
|
|
|
500,000
|
|
|
495,710
|
|
|
483,994
|
|
||||||
4.500% Senior Notes due 2028
|
|
400,000
|
|
|
395,113
|
|
|
390,920
|
|
|
400,000
|
|
|
394,631
|
|
|
377,475
|
|
||||||
4.750% Senior Notes due 2028
|
|
400,000
|
|
|
396,190
|
|
|
400,962
|
|
|
400,000
|
|
|
395,841
|
|
|
384,370
|
|
||||||
5.450% Senior Notes due 2044
|
|
600,000
|
|
|
593,470
|
|
|
533,710
|
|
|
600,000
|
|
|
593,349
|
|
|
522,386
|
|
||||||
5.300% Senior Notes due 2048
|
|
700,000
|
|
|
686,843
|
|
|
610,841
|
|
|
700,000
|
|
|
686,648
|
|
|
605,327
|
|
||||||
5.500% Senior Notes due 2048
|
|
350,000
|
|
|
342,432
|
|
|
310,198
|
|
|
350,000
|
|
|
342,328
|
|
|
311,536
|
|
||||||
RCF
|
|
380,000
|
|
|
380,000
|
|
|
380,000
|
|
|
220,000
|
|
|
220,000
|
|
|
220,000
|
|
||||||
Term loan facility
|
|
3,000,000
|
|
|
3,000,000
|
|
|
3,000,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
APCWH Note Payable
|
|
—
|
|
|
—
|
|
|
—
|
|
|
427,493
|
|
|
427,493
|
|
|
427,493
|
|
||||||
Total long-term debt
|
|
$
|
8,000,000
|
|
|
$
|
7,951,565
|
|
|
$
|
7,849,818
|
|
|
$
|
5,267,493
|
|
|
$
|
5,214,874
|
|
|
$
|
4,976,815
|
|
(1)
|
Fair value is measured using the market approach and Level-2 fair value inputs.
|
(2)
|
Amounts are considered affiliate. See Note 14.
|
thousands
|
|
Carrying Value
|
||
Balance at December 31, 2017
|
|
$
|
3,591,678
|
|
RCF borrowings
|
|
540,000
|
|
|
APCWH Note Payable borrowings
|
|
321,780
|
|
|
Issuance of 4.500% Senior Notes due 2028
|
|
400,000
|
|
|
Issuance of 5.300% Senior Notes due 2048
|
|
700,000
|
|
|
Issuance of 4.750% Senior Notes due 2028
|
|
400,000
|
|
|
Issuance of 5.500% Senior Notes due 2048
|
|
350,000
|
|
|
Repayment of 2.600% Senior Notes due 2018
|
|
(350,000
|
)
|
|
Repayments of RCF borrowings
|
|
(690,000
|
)
|
|
Other
|
|
(20,584
|
)
|
|
Balance at December 31, 2018
|
|
$
|
5,242,874
|
|
RCF borrowings
|
|
1,160,000
|
|
|
Term loan facility borrowings
|
|
3,000,000
|
|
|
APCWH Note Payable borrowings
|
|
11,000
|
|
|
Finance lease liabilities
|
|
7,873
|
|
|
Repayments of RCF borrowings
|
|
(1,000,000
|
)
|
|
Repayment of WGP RCF borrowings
|
|
(28,000
|
)
|
|
Repayment of APCWH Note Payable
|
|
(439,595
|
)
|
|
Other
|
|
5,286
|
|
|
Balance at December 31, 2019
|
|
$
|
7,959,438
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
Third parties
|
|
|
|
|
|
|
||||||
Long-term and short-term debt
|
|
$
|
(315,872
|
)
|
|
$
|
(200,454
|
)
|
|
$
|
(143,400
|
)
|
Amortization of debt issuance costs and commitment fees
|
|
(12,424
|
)
|
|
(9,110
|
)
|
|
(7,970
|
)
|
|||
Capitalized interest
|
|
26,980
|
|
|
32,479
|
|
|
9,074
|
|
|||
Total interest expense – third parties
|
|
(301,316
|
)
|
|
(177,085
|
)
|
|
(142,296
|
)
|
|||
Affiliates
|
|
|
|
|
|
|
||||||
APCWH Note Payable
|
|
(1,833
|
)
|
|
(6,746
|
)
|
|
(153
|
)
|
|||
Finance lease liabilities
|
|
(137
|
)
|
|
—
|
|
|
—
|
|
|||
Deferred purchase price obligation – Anadarko
|
|
—
|
|
|
—
|
|
|
(71
|
)
|
|||
Total interest expense – affiliates
|
|
(1,970
|
)
|
|
(6,746
|
)
|
|
(224
|
)
|
|||
Interest expense
|
|
$
|
(303,286
|
)
|
|
$
|
(183,831
|
)
|
|
$
|
(142,520
|
)
|
thousands except lease term and discount rate
|
|
Operating Leases
|
|
Finance Leases
|
||||
Assets
|
|
|
|
|
||||
Other assets
|
|
$
|
3,985
|
|
|
$
|
—
|
|
Net property, plant, and equipment
|
|
—
|
|
|
7,892
|
|
||
Total lease assets (1)
|
|
$
|
3,985
|
|
|
$
|
7,892
|
|
|
|
|
|
|
||||
Liabilities
|
|
|
|
|
||||
Accrued liabilities
|
|
$
|
1,805
|
|
|
$
|
—
|
|
Short-term debt
|
|
—
|
|
|
7,873
|
|
||
Other liabilities
|
|
3,035
|
|
|
—
|
|
||
Total lease liabilities (1)
|
|
$
|
4,840
|
|
|
$
|
7,873
|
|
|
|
|
|
|
||||
Weighted-average remaining lease term (years)
|
|
5
|
|
|
—
|
|
||
Weighted-average discount rate
|
|
4.7
|
%
|
|
2.9
|
%
|
(1)
|
Includes additions to ROU assets and lease liabilities of $8.5 million related to finance leases for the year ended December 31, 2019.
|
thousands
|
|
Year Ended
December 31, 2019 |
||
Operating lease cost
|
|
$
|
6,932
|
|
Short-term lease cost
|
|
1,295
|
|
|
Variable lease cost
|
|
256
|
|
|
Sublease income
|
|
(414
|
)
|
|
Finance lease cost
|
|
|
||
Amortization of ROU assets
|
|
562
|
|
|
Interest on lease liabilities
|
|
137
|
|
|
Total lease cost
|
|
$
|
8,768
|
|
thousands
|
|
Operating Leases
|
|
Finance Leases
|
||||
Operating cash flows
|
|
$
|
7,042
|
|
|
$
|
118
|
|
Financing cash flows
|
|
—
|
|
|
508
|
|
thousands
|
|
Operating Leases
|
|
Finance Leases
|
||||
2020
|
|
$
|
1,969
|
|
|
$
|
7,934
|
|
2021
|
|
612
|
|
|
—
|
|
||
2022
|
|
618
|
|
|
—
|
|
||
2023
|
|
625
|
|
|
—
|
|
||
2024
|
|
449
|
|
|
—
|
|
||
Thereafter
|
|
1,209
|
|
|
—
|
|
||
Total lease payments
|
|
5,482
|
|
|
7,934
|
|
||
Less portion representing imputed interest
|
|
642
|
|
|
61
|
|
||
Total lease liabilities
|
|
$
|
4,840
|
|
|
$
|
7,873
|
|
thousands
|
|
|
||
2019
|
|
$
|
8,711
|
|
2020
|
|
2,236
|
|
|
2021
|
|
460
|
|
|
2022
|
|
467
|
|
|
2023
|
|
473
|
|
|
Thereafter
|
|
1,547
|
|
|
Total lease payments
|
|
$
|
13,894
|
|
thousands
|
|
|
||
2020
|
|
$
|
157,582
|
|
2021
|
|
193,925
|
|
|
2022
|
|
—
|
|
|
2023
|
|
—
|
|
|
2024
|
|
—
|
|
|
Thereafter
|
|
—
|
|
|
Total lease payments
|
|
$
|
351,507
|
|
•
|
$1.0 billion in aggregate principal amount of 3.100% Senior Notes due 2025, $1.2 billion in aggregate principal amount of 4.050% Senior Notes due 2030, and $1.0 billion in aggregate principal amount of 5.250% Senior Notes due 2050, offered to the public at prices of 99.962%, 99.900%, and 99.442%, respectively, of the face amount (collectively referred to as the “Senior Notes”). Interest is paid on each such series semi-annually on February 1 and August 1 of each year, beginning August 1, 2020; and
|
•
|
$300.0 million in aggregate principal amount of floating rate Senior Notes due 2023 (the “Floating Rate Notes”). Interest is paid quarterly in arrears on January 13, April 13, July 13, and October 13 of each year, beginning April 13, 2020. Interest will accrue from January 13, 2020 at a benchmark rate (which will initially be a three-month LIBOR rate) on the interest determination date plus 0.85%.
|
thousands except per-unit amounts
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
2019
|
|
|
|
|
|
|
|
|
||||||||
Total revenues and other
|
|
$
|
671,883
|
|
|
$
|
685,054
|
|
|
$
|
666,027
|
|
|
$
|
723,210
|
|
Equity income, net – affiliates
|
|
57,992
|
|
|
63,598
|
|
|
53,893
|
|
|
62,035
|
|
||||
Cost of product
|
|
114,063
|
|
|
122,877
|
|
|
97,800
|
|
|
109,507
|
|
||||
Operating income (loss)
|
|
318,928
|
|
|
310,060
|
|
|
268,725
|
|
|
333,630
|
|
||||
Net income (loss)
|
|
211,979
|
|
|
175,058
|
|
|
125,223
|
|
|
295,440
|
|
||||
Net income (loss) attributable to Western Midstream Partners, LP
|
|
118,660
|
|
|
169,594
|
|
|
121,217
|
|
|
287,770
|
|
||||
Net income (loss) per common unit – basic and diluted (1)
|
|
0.30
|
|
|
0.37
|
|
|
0.27
|
|
|
0.62
|
|
||||
2018
|
|
|
|
|
|
|
|
|
||||||||
Total revenues and other
|
|
$
|
501,054
|
|
|
$
|
518,078
|
|
|
$
|
587,900
|
|
|
$
|
692,626
|
|
Equity income, net – affiliates
|
|
30,229
|
|
|
49,430
|
|
|
54,215
|
|
|
61,595
|
|
||||
Cost of product
|
|
94,318
|
|
|
95,656
|
|
|
101,035
|
|
|
124,496
|
|
||||
Operating income (loss)
|
|
224,867
|
|
|
114,214
|
|
|
257,554
|
|
|
264,647
|
|
||||
Net income (loss)
|
|
181,010
|
|
|
67,167
|
|
|
198,560
|
|
|
183,917
|
|
||||
Net income (loss) attributable to Western Midstream Partners, LP
|
|
131,527
|
|
|
100,184
|
|
|
151,357
|
|
|
168,503
|
|
||||
Net income (loss) per common unit – basic and diluted (1)
|
|
0.46
|
|
|
0.31
|
|
|
0.49
|
|
|
0.43
|
|
(1)
|
Represents net income (loss) earned on and subsequent to the date of the acquisition of assets from Anadarko.
|
Name
|
|
Age
|
|
Position with Western Midstream Holdings, LLC
|
|
Glenn Vangolen
|
|
60
|
|
|
Chairman of the Board (effective August 8, 2019)
|
Michael P. Ure
|
|
43
|
|
|
President, Chief Executive Officer and Director
(effective August 8, 2019)
|
Michael C. Pearl
|
|
48
|
|
|
Senior Vice President and Chief Financial Officer
(effective October 17, 2019)
|
Robert W. Bourne
|
|
64
|
|
|
Senior Vice President and Chief Commercial Officer
(effective October 17, 2019)
|
Craig W. Collins
|
|
47
|
|
|
Senior Vice President and Chief Operating Officer
(effective August 8, 2019)
|
Christopher B. Dial
|
|
43
|
|
|
Senior Vice President, General Counsel and Corporate Secretary
(effective December 16, 2019)
|
Catherine A. Green
|
|
46
|
|
|
Vice President and Chief Accounting Officer
(effective October 17, 2019) |
Charles G. Griffie
|
|
46
|
|
|
Senior Vice President, Operations and Engineering
(effective October 17, 2019)
|
Robin H. Fielder
|
|
39
|
|
|
President, Chief Executive Officer and Director
(through August 7, 2019)
|
Jaime R. Casas
|
|
49
|
|
|
Senior Vice President, Chief Financial Officer and Treasurer
(through October 16, 2019)
|
Steven D. Arnold
|
|
59
|
|
|
Director (effective February 28, 2019)
|
Marcia E. Backus
|
|
65
|
|
|
Director (effective August 8, 2019)
|
Peter J. Bennett
|
|
51
|
|
|
Director (effective August 8, 2019)
|
Oscar K. Brown
|
|
49
|
|
|
Director (effective August 8, 2019)
|
James R. Crane
|
|
66
|
|
|
Director (effective February 28, 2019)
|
Thomas R. Hix
|
|
72
|
|
|
Director
|
Jennifer M. Kirk
|
|
45
|
|
|
Director (effective August 8, 2019)
|
Craig W. Stewart
|
|
65
|
|
|
Director
|
David J. Tudor
|
|
60
|
|
|
Director
|
Glenn Vangolen
Houston, Texas
Director since:
August 2019
Not Independent
|
Biography/Qualifications
Mr. Vangolen has served as a director of our general partner’s Board of Directors since August 2019. Mr. Vangolen has been Senior Vice President, Business Support of Occidental since February 2015. In this role, Mr. Vangolen oversees the Human Resources and Administration; Information Technology; Flight Operations; Health, Environment, Safety, and Security; Government Relations and Corporate Secretary functions of Occidental. Mr. Vangolen has held positions of increasing responsibility in the oil and gas and corporate segments within Occidental, including senior leadership positions in the Middle East.
|
|
|
Michael P. Ure
Houston, Texas
Director since:
August 2019
Not Independent
Officer since:
August 2019
|
Biography/Qualifications
Mr. Ure has served as President and Chief Executive Officer of our general partner and as a director of our general partner’s Board of Directors since August 2019. Prior to joining WES, Mr. Ure served as Senior Vice President, Business Development of Occidental Oil and Gas beginning in July 2017 and as Vice President, Mergers and Acquisitions of Occidental from October 2014 to July 2017. Mr. Ure held a leadership role in evaluating acquisition and divestiture opportunities including, during his tenure, accountability for Occidental’s business development activities in North and Latin America. Prior to joining Occidental, Mr. Ure served in a leadership role with Shell Exploration and Production’s Upstream Americas Business Development organization and as an investment banker in New York, London, and Houston; most recently with Goldman, Sachs & Co. During his career, Mr. Ure has worked on total closed transactions representing more than $150 billion in value.
|
|
|
Michael C. Pearl
Houston, Texas
Officer since:
October 2019
|
Biography/Qualifications
Mr. Pearl has served as Senior Vice President and Chief Financial Officer of our general partner since October 2019. Mr. Pearl joined Anadarko in 2004 and served in various leadership positions within Anadarko’s accounting and finance organization, including Director Corporate Tax, Corporate Controller, Vice President Finance and Treasurer, and most recently as Senior Vice President, Investor Relations. Mr. Pearl also served as Senior Vice President and Chief Financial Officer of the general partner of Western Midstream Operating, LP (formerly Western Gas Partners, LP) at the time of its 2008 IPO. Prior to joining Anadarko, Mr. Pearl began his career at EY, where he held positions of increasing responsibility in corporate tax and finance.
|
|
|
Robert W. Bourne
Houston, Texas
Officer since:
October 2019
|
Biography/Qualifications
Mr. Bourne has served as Senior Vice President and Chief Commercial Officer of our general partner since October 2019. Prior to joining WES, Mr. Bourne served as a member of the board of directors of Altus Midstream Company from November 2018 to August 2019. Mr. Bourne also served as a member of the board of directors and Vice President of Business Development — Marketing of Apache Corporation from April 2017 to August 2019. Prior to joining Apache Corporation, Mr. Bourne served as a consultant advising Smith Production Inc. Mr. Bourne served as Senior Vice President of Business Development at American Midstream GP LLC, the general partner of American Midstream Partners, LP from November 2014 until December 31, 2015. Mr. Bourne has more than 30 years of experience in midstream corporate business development focused on producer and end-user relations, and was one of the founding members of the executive management team for Coral Energy.
|
|
|
Craig W. Collins
Houston, Texas
Officer since:
August 2019
|
Biography/Qualifications
Mr. Collins has served as Senior Vice President and Chief Operating Officer of our general partner since August 2019. Mr. Collins served as Vice President, Midstream of Occidental from June 2019 through December 2019. In that role, Mr. Collins was responsible for leading Occidental’s midstream operations business unit. From April 2018 to April 2019, Mr. Collins served as Vice President and Chief Operating Officer — Midstream, of Alta Mesa Resources, Inc., which filed a petition under the federal bankruptcy laws in September 2019. From February 2017 to April 2018, Mr. Collins served as Senior Vice President and Chief Operating Officer of the general partner and the general partner of Western Gas Partners, LP (now WES Operating) (“Western Gas”). Mr. Collins previously served as Director of Midstream Engineering for Anadarko from July 2016 to February 2017, during which time he was responsible for the engineering and construction of midstream infrastructure for Anadarko and Western Gas. Mr. Collins joined Anadarko in 2003 and served in several roles of increasing responsibility in Anadarko’s Treasury, Corporate Development, and Midstream groups.
|
|
|
Thomas R. Hix
Houston, Texas
Director since:
January 2013
Independent
|
Biography/Qualifications
Mr. Hix has served as a director of our general partner and as a member of the Audit Committee of the Board of Directors since January 2013. Mr. Hix has served as Chairman of the Audit Committee since August 2019 and served as Chairman of the Special Committee of the Board of Directors from January 2013 to August 2019. Mr. Hix has been a business consultant since 2003, and previously served as Senior Vice President of Finance and Chief Financial Officer of Cooper Cameron Corporation from 1995 to 2003. Prior to joining Cooper Cameron Corporation, Mr. Hix held several executive finance and accounting positions in the energy industry. Mr. Hix has significant expertise in finance and accounting and experience in mergers and acquisitions. Mr. Hix currently serves as a director of Ascent Resources, LLC, a privately owned exploration and production company focused on natural gas, oil, and NGLs in the Appalachian basin. Mr. Hix previously served as a director of Health Care Services Corporation from 2004 to November 2017, as a director of EP Energy Corporation from April 2014 to December 2017, as a director of El Paso Corporation from 2004 to May 2012, and as a director of Rowan Companies plc from 2009 to April 2019.
|
|
|
Jennifer M. Kirk
Houston, Texas
Director since:
August 2019
Not Independent
|
Biography/Qualifications
Ms. Kirk has served as a director of our general partner’s Board of Directors since August 2019. She was appointed Senior Vice President, Integration, of Occidental in August 2019. In her current role, Ms. Kirk is responsible for overseeing the integration of Anadarko and facilitating Occidental’s achievement of its synergy targets. Prior to her current position with Occidental, Ms. Kirk served as Vice President, Controller and Principal Accounting Officer of Occidental from 2014 to August 2019, and was responsible for the direct oversight of Occidental’s financial reporting, accounting, and internal controls functions. Ms. Kirk joined Occidental in 1999 and has served in financial roles of increasing responsibility and leadership. Prior to joining Occidental, Ms. Kirk was with Arthur Andersen, LLP. Ms. Kirk also serves on the board of directors of Republic Services, Inc., where she serves as chair of the Audit Committee and as a member of the Sustainability & Corporate Responsibility Committee. Ms. Kirk also serves on the boards of the Boys and Girls Club of the Greater Houston Area and the Houston Women’s Chamber.
|
|
|
Craig W. Stewart
Calgary, Alberta, Canada
Director since:
January 2013
Independent
|
Biography/Qualifications
Mr. Stewart has served as a director of our general partner and as a member of the Special Committee of the Board of Directors since January 2013. Mr. Stewart also served on the Audit Committee of our general partner’s Board of Directors from January 2013 through August 2019. Mr. Stewart served as a director of RMP Energy Inc. from 2011 to May 2017, having served as its Executive Chairman from 2011 to January 2017, and as Chairman, President and Chief Executive Officer of a predecessor entity, RMP Energy Ltd., from 2008 until 2011. Mr. Stewart served as President and Chief Executive Officer of Rider Resources Ltd. from 2003 to 2008, and prior to joining Rider Resources, held various executive and director positions with companies in the energy industry.
|
|
|
David J. Tudor
Houston, Texas
Director since:
December 2012
Independent
|
Biography/Qualifications
Mr. Tudor has served as a director of our general partner and as a member of the Audit Committee of the Board of Directors since December 2012. Mr. Tudor has served as Chairman of the Special Committee of our general partner’s Board of Directors since August 2019 and served as Chairman of the Audit Committee from December 2012 through August 2019. Mr. Tudor also served as a director of the general partner of Western Gas Partners, LP (now WES Operating) and as Chairman of the Audit Committee of WES Operating’s board of directors from 2008 to February 2019, and as a member of the Special Committee of WES Operating’s board of directors from 2008 to December 2012. Since May 2016, Mr. Tudor has served as Chief Executive Officer and General Manager of Associated Electric Cooperative Inc., a member-owned, member-governed wholesale power provider serving Missouri, Iowa, and Oklahoma. From May 2013 to May 2016, Mr. Tudor served as President and Chief Executive Officer of Champion Energy Services, a retail electric provider. From 1999 through 2013, Mr. Tudor was the President and Chief Executive Officer of ACES, an Indianapolis-based commodity risk management company owned by 21 generation and transmission cooperatives throughout the United States. Prior to joining ACES, Mr. Tudor was the Executive Vice President & Chief Operating Officer of PG&E Energy Trading, where he managed commercial operations in the United States and Canada.
|
Named Executive Officers of Our General Partner
|
|
Time
Allocation
|
|
Occidental Corporate Officer
|
Michael P. Ure (1)
|
|
90%
|
|
Yes
|
Michael C. Pearl (1)
|
|
100%
|
|
No
|
Craig W. Collins (1)
|
|
100%
|
|
No
|
Robert W. Bourne (1)
|
|
100%
|
|
No
|
Charles G. Griffie (1)
|
|
100%
|
|
No
|
Robin H. Fielder
|
|
75%
|
|
No
|
Jaime R. Casas
|
|
70%
|
|
Yes
|
John D. Montanti
|
|
70%
|
|
No
|
(1)
|
Based upon their respective appointment dates, the full-year 2019 prorated allocation percentages for Messrs. Ure, Pearl, Collins, Bourne, and Griffie are as follows: 35% for Mr. Ure, 40% for Mr. Pearl, 40% for Mr. Collins, 40% for Mr. Bourne, and 20% for Mr. Griffie. Compensation amounts shown herein for these named executive officers do not include compensation that was paid or awards that were granted by Anadarko or Occidental prior to the named executive officer’s commencement of service with us.
|
•
|
base salary;
|
•
|
annual cash incentives;
|
•
|
equity-based compensation, which, prior to the Occidental Merger, included equity-based compensation under Anadarko’s 2012 Omnibus Incentive Compensation Plan, as amended and restated (the “Omnibus Plan”), for former Anadarko employees and Occidental’s 2015 Long-Term Incentive Plan (the “Occidental LTIP Plan”) for former Occidental employees;
|
•
|
retention awards for certain of our named executive officers; however, we will not bear any costs associated with such awards; and
|
•
|
certain other benefits that were provided on the same basis to other eligible Anadarko and Occidental employees, including welfare and retirement benefits, severance and change of control benefits, and other benefits.
|
Named Executive Officers
|
|
Base Salary
(Unallocated)
|
||
Michael P. Ure
|
|
$
|
650,000
|
|
Michael C. Pearl
|
|
455,000
|
|
|
Craig W. Collins
|
|
455,000
|
|
|
Robert W. Bourne
|
|
405,000
|
|
|
Charles G. Griffie
|
|
405,000
|
|
Named Executive Officers
|
|
Bonus Opportunity
(Unallocated)
|
|
Michael P. Ure
|
|
100
|
%
|
Michael C. Pearl
|
|
86
|
%
|
Craig W. Collins
|
|
86
|
%
|
Robert W. Bourne
|
|
81
|
%
|
Charles G. Griffie
|
|
85
|
%
|
•
|
retirement benefits to match competitive industry practices, including participation in a savings plan, savings restoration plan, retirement plan, and retirement restoration plan;
|
•
|
severance benefits, as described below under the heading Potential Payments Upon Termination or Change of Control;
|
•
|
director 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 deferred compensation plans, and personal excess liability insurance; and
|
•
|
certain benefits that are also provided to all other eligible U.S.-based employees, including medical, dental, vision, flexible spending and health savings accounts, paid time off, life insurance, and disability coverage.
|
Name and Principal Position
|
|
Year
|
|
Salary
($) (1)
|
|
Stock
Awards
($) (2)
|
|
Option
Awards
($) (3)
|
|
Non-Equity
Incentive Plan Compensation
($) (4)
|
|
All Other
Compensation
($) (5)
|
|
Total
($)
|
||||||
Michael P. Ure
|
|
2019
|
|
147,981
|
|
|
1,080,029
|
|
|
—
|
|
|
162,000
|
|
|
43,252
|
|
|
1,433,262
|
|
President and
|
|
2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Chief Executive Officer
|
|
2017
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Robin H. Fielder
|
|
2019
|
|
223,846
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
54,494
|
|
|
278,340
|
|
Former President and
|
|
2018
|
|
23,019
|
|
|
384,963
|
|
|
201,309
|
|
|
21,313
|
|
|
5,905
|
|
|
636,509
|
|
Chief Executive Officer
|
|
2017
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Michael C. Pearl
|
|
2019
|
|
167,308
|
|
|
—
|
|
|
—
|
|
|
160,615
|
|
|
41,909
|
|
|
369,832
|
|
Senior Vice President and
|
|
2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Chief Financial Officer
|
|
2017
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Jaime R. Casas
|
|
2019
|
|
281,942
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
69,281
|
|
|
351,223
|
|
Former Senior Vice President, Chief
|
|
2018
|
|
348,577
|
|
|
1,650,799
|
|
|
392,547
|
|
|
271,890
|
|
|
89,029
|
|
|
2,752,842
|
|
Financial Officer and Treasurer
|
|
2017
|
|
208,731
|
|
|
1,257,309
|
|
|
904,934
|
|
|
135,675
|
|
|
71,607
|
|
|
2,578,256
|
|
Charles G. Griffie
|
|
2019
|
|
73,077
|
|
|
208,008
|
|
|
—
|
|
|
70,154
|
|
|
18,360
|
|
|
369,599
|
|
Senior Vice President, Operations
|
|
2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
and Engineering
|
|
2017
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Craig W. Collins
|
|
2019
|
|
138,462
|
|
|
500,049
|
|
|
—
|
|
|
168,000
|
|
|
25,826
|
|
|
832,337
|
|
Senior Vice President and
|
|
2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Chief Operating Officer
|
|
2017
|
|
146,827
|
|
|
1,029,025
|
|
|
279,272
|
|
|
91,209
|
|
|
49,090
|
|
|
1,595,423
|
|
Robert W. Bourne
|
|
2019
|
|
136,500
|
|
|
1,250,029
|
|
|
—
|
|
|
154,932
|
|
|
10,680
|
|
|
1,552,141
|
|
Senior Vice President and
|
|
2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Chief Commercial Officer
|
|
2017
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
John D. Montanti
|
|
2019
|
|
209,794
|
|
|
156,139
|
|
|
—
|
|
|
—
|
|
|
52,149
|
|
|
418,082
|
|
Former Vice President, General
|
|
2018
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Counsel and Corporate Secretary
|
|
2017
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
The amounts in this column reflect the base salary compensation allocated to us by Anadarko and Occidental for the years ended December 31, 2019, 2018, and 2017. Amounts for Messrs. Ure, Pearl, Collins, Bourne, and Griffie for the year ended December 31, 2019, reflect base salary compensation earned and allocated since their appointments as officers of our general partner.
|
(2)
|
The amounts in this column reflect an allocation to us of the aggregate grant date fair value of the awards, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for non-option stock awards granted pursuant to the Omnibus Plan. The value ultimately realized upon the actual vesting of the award(s) may or may not be equal to this determined value. For Messrs. Griffie and Montanti, their awards represent a grant prior to the acquisition of Anadarko by Occidental on August 8, 2019. For a discussion of valuation assumptions for the awards under the Omnibus Plan, see Note 14—Stock-Based Incentive Plans in the Notes to Consolidated Financial Statements included under Part II, Item 8 of Occidental’s Form 10-K for the year ended December 31, 2019 (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 2019, see the Grants of Plan-Based Awards in 2019 table. The amounts in this column also reflect the allocation of performance unit awards, where such gross amounts were subject to market conditions and have been valued based on the probable outcome of the market conditions as of the grant date.
|
(3)
|
The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for option awards granted pursuant to the Omnibus Plan. See note (2) above for valuation assumptions. The value ultimately realized upon the exercise of the stock option(s) may or may not be equal to this determined value.
|
(4)
|
The amounts in this column reflect annual cash bonus compensation expected to be allocated to us for the year ended December 31, 2019, and the amounts allocated to us for the years ended December 31, 2018 and 2017.
|
(5)
|
The amounts in this column reflect the compensation expenses related to Anadarko’s and Occidental’s retirement and savings plans that were allocated to us for the years ended December 31, 2019, 2018, and 2017. Amounts for Messrs. Ure, Pearl, Collins, Bourne, and Griffie for the year ended December 31, 2019, reflect expenses allocated since their appointments as officers of our general partner. The 2019 allocated expenses are detailed in the table below:
|
Name
|
|
Retirement Plans
Expense
|
|
Savings Plans
Expense
|
||||
Michael P. Ure
|
|
$
|
—
|
|
|
$
|
43,252
|
|
Robin H. Fielder
|
|
27,381
|
|
|
27,113
|
|
||
Michael C. Pearl
|
|
23,310
|
|
|
18,599
|
|
||
Jaime R. Casas
|
|
35,222
|
|
|
34,059
|
|
||
Charles G. Griffie
|
|
10,485
|
|
|
7,875
|
|
||
Craig W. Collins
|
|
—
|
|
|
25,826
|
|
||
Robert W. Bourne
|
|
—
|
|
|
10,680
|
|
||
John D. Montanti
|
|
27,736
|
|
|
24,413
|
|
|
|
|
|
|
|
|
|
|
|
All
Other
Stock
Awards:
Number of
Shares of
Stock or
Units
(#) (3)
|
|
All Other
Option
Awards:
Number of
Securities
Underlying
Options
(#)
|
|
Exercise
or
Base Price
of Option
Awards
($/Sh)
|
|
Grant
Date
Fair Value
of Stock
and
Option
Awards
($) (4)
|
||||||||||||
|
|
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
(#)
|
|
|
|
|
||||||||||||
Michael P. Ure
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
—
|
|
—
|
|
|
135,000
|
|
|
162,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
02/15/2019
|
|
|
|
|
|
|
|
2,299
|
|
|
9,197
|
|
|
18,394
|
|
|
|
|
|
|
|
|
540,023
|
|
||||
02/15/2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,037
|
|
|
|
|
|
|
540,006
|
|
||||||
Michael C. Pearl
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
—
|
|
—
|
|
|
133,846
|
|
|
160,615
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Charles G. Griffie
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
—
|
|
—
|
|
|
58,462
|
|
|
70,154
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
02/12/2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,860
|
|
|
|
|
|
|
208,008
|
|
||||||
Craig W. Collins
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
—
|
|
—
|
|
|
140,000
|
|
|
168,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
05/30/2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,633
|
|
|
|
|
|
|
500,049
|
|
||||||
Robert W. Bourne
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
—
|
|
—
|
|
|
129,110
|
|
|
154,932
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
08/09/2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,523
|
|
|
|
|
|
|
1,250,029
|
|
||||||
John D. Montanti
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
03/12/2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,564
|
|
|
|
|
|
|
156,139
|
|
(1)
|
Reflects the estimated 2019 annual cash incentive payouts allocable to us. 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 Agreement. The expense expected to be allocated to us for the actual bonus payouts under the annual incentive program for 2019 is reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.
|
(2)
|
Reflects, as of the time of grant, the estimated future payout allocable to us under performance units awarded in 2019. Mr. Ure is eligible to earn from 0% to 200% of the targeted award based on Occidental’s relative total shareholder return performance over a three-year performance period. The threshold value represents the minimum payment (other than zero) that was eligible to be earned.
|
(3)
|
Reflects the allocable number of shares of restricted stock and restricted stock units awarded in 2019 under the Omnibus Plan for Messrs. Griffie and Montanti and the Occidental LTIP Plan for Messrs. Ure, Collins, and Bourne, respectively. For Messrs. Griffie and Montanti, their awards represent a grant prior to the acquisition of Anadarko by Occidental on August 8, 2019. Mr. Ure’s award vests ratably on each February 28, 2020, 2021, and 2022. For Messrs. Collins, Bourne, and Montanti, these awards were eligible to vest ratably on each of the first three anniversaries of the grant date. Mr. Griffie’s awards will fully vest four years from the grant date.
|
(4)
|
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 at the time of grant made to named executives in 2019 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 and the Occidental LTIP Plan, see Note 14-Stock-Based Incentive Plans in the Notes to Consolidated Financial Statements under Part II, Item 8 of Occidental’s Form 10-K for the year ended December 31, 2019 (which is not, and shall not be deemed to be, incorporated by reference herein). There were no grants of stock options in 2019.
|
(1)
|
Stock options have a seven-year term and will vest ratably over three years in equal installments on the first, second, and third anniversaries of the date of grant. Stock option awards do not accrue dividends or dividend equivalents.
|
(2)
|
Generally, the restricted stock units will vest ratably over three years in installments on the first, second, and third anniversaries of the grant date. Mr. Ure’s 2017 restricted stock units will fully vest on February 28, 2020, his 2018 restricted stock units vested on February 28, 2019, and the remaining unvested portion will vest ratably on February 28, 2020 and 2021. One-third of Mr. Ure’s February 2019 restricted stock units will vest on February 28, 2020, 2021, and 2022. Messrs. Pearl’s and Griffie’s restricted stock units granted on November 10, 2016, and February 12, 2019, respectively, vest four years from the grant date. At the end of each vesting period, unless deferred, the number of restricted stock units that vest are settled in shares of unrestricted Occidental common stock, less applicable withholding taxes. For restricted stock units, dividend equivalents are accrued and reinvested in additional shares of common stock, less applicable withholding taxes. Pursuant to the Occidental Merger Agreement, each outstanding award of restricted stock units converted into a restricted stock and cash unit award of Occidental. Respectively, Messrs. Pearl and Griffie have the following cash portions outstanding as of December 31, 2019, that will vest ratably three years in installments on the first, second, and third anniversary of the grant date; Messrs. Pearl’s and Griffie’s award granted on November 10, 2016, and February 12, 2019, respectively, vests four years from grant date:
|
Named Executive Officers
|
|
Cash Portions Outstanding
|
||
Michael C. Pearl
|
|
|
||
11/10/2016
|
|
$
|
369,842
|
|
11/14/2017
|
|
81,154
|
|
|
11/15/2018
|
|
43,498
|
|
|
Charles G. Griffie
|
|
|
||
11/28/2018
|
|
29,723
|
|
|
11/28/2018
|
|
426,104
|
|
|
02/12/2019
|
|
289,901
|
|
(3)
|
The number of outstanding performance units and the estimated payout percentages disclosed for each award, for Mr. Ure, are calculated based on Occidental’s relative performance ranking as of December 31, 2019, and are not necessarily indicative of what the payout percent earned will be at the end of each three-year performance period. The three-year performance period generally starts in January in the year of grant and ends on December 31, 2020 and 2021 for 2018 and 2019 grants, respectively. Occidental’s relative performance rankings as of December 31, 2019 were 0% for the February 2018 and the February 2019 grants. For Mr. Ure’s award granted in February 2017 with a performance period beginning in 2019, the performance unit award is not outstanding as the award paid out at 0%. For Messrs. Pearl and Griffie, all outstanding performance units immediately vested on August 8, 2019, as provided under the terms of the Occidental Merger Agreement, and are not allocable to the Partnership.
|
|
|
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)
|
||||
Michael P. Ure
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Robin H. Fielder
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Michael C. Pearl
|
|
—
|
|
|
—
|
|
|
583
|
|
|
22,607
|
|
Jaime R. Casas
|
|
—
|
|
|
—
|
|
|
920
|
|
|
35,249
|
|
Charles G. Griffie
|
|
—
|
|
|
—
|
|
|
327
|
|
|
12,653
|
|
Craig W. Collins
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Robert W. Bourne
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
John D. Montanti
|
|
—
|
|
|
—
|
|
|
669
|
|
|
41,331
|
|
(1)
|
Shares acquired and values realized on exercise include options exercised in 2019. The amounts shown in the Value Realized on Exercise column represent the difference between the market price of common stock at exercise and the applicable exercise price of such option(s). 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. Pursuant to the Occidental Merger Agreement, for Messrs. Pearl, Griffie, and Casas and Ms. Fielder, each outstanding stock option was canceled and converted into the right to receive an amount in cash and was not allocable to the Partnership.
|
(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 2019 of shares of restricted stock or restricted stock units, performance units, or phantom units. For each named executive officer, the amount shown in the Value Realized on Vesting column represents the aggregate number of restricted stock units or shares of restricted stock held by such named executive officer that vested during 2019 multiplied by the common stock price on the applicable vesting date(s). For shares of restricted stock or restricted stock units, the actual value ultimately realized by the named executive officer may be more or less than the value realized calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise or vesting occurrence. Mr. Ure’s shares acquired and values realized were incurred in early 2019 before becoming an executive officer of the Partnership and were never allocable to the Partnership.
|
•
|
A cash lump sum equal to (A) 50% of the sum of (i) the participant’s monthly base salary plus (ii) the highest annual bonus received by the participant over the previous three years, divided by twelve, multiplied by the number of years of service by the participant (clauses (i) and (ii), “Monthly Compensation”) and (B) one month of Monthly Compensation for each $10,000 of annual compensation (base salary plus highest annual bonus), rounding up to the next highest whole multiple of $10,000 if the participant’s annual compensation is not a multiple of $10,000 (the “Severance Benefit”);
|
•
|
Pro-rata annual bonus based on the participant’s target bonus percentage; and
|
•
|
Continuation of medical and dental insurance coverage for up to six months following termination of employment.
|
|
|
Mr. Ure
|
|
Mr. Collins
|
|
Mr. Bourne
|
||||||
Cash Severance (1)
|
|
$
|
2,825,000
|
|
|
$
|
400,000
|
|
|
$
|
390,000
|
|
Total
|
|
$
|
2,825,000
|
|
|
$
|
400,000
|
|
|
$
|
390,000
|
|
(1)
|
Pursuant to the terms of the Services Agreement, our liability for severance owed to Messrs. Collins and Bourne is capped at one year of base salary, which is the amount that would have been payable if such officers were subject to the Anadarko Officer Severance Plan. The amount above for Mr. Ure reflects the single-trigger broad-based rights extended to him under the Anadarko COC Plan, as such amount is not capped under the Services Agreement. Due to the waiver of certain change of control rights discussed above, Messrs. Pearl and Griffie do not have arrangements covering involuntary not-for-cause termination other than agreements with Occidental providing for the vesting of equity or acceleration of retention payments for which, in either case, we are not obligated under the Services Agreement.
|
|
|
Mr. Ure
|
|
Mr. Pearl
|
|
Mr. Collins
|
|
Mr. Bourne
|
|
Mr. Griffie
|
||||||||||
Cash Severance (1)
|
|
$
|
2,825,000
|
|
|
$
|
435,000
|
|
|
$
|
1,733,123
|
|
|
$
|
1,297,110
|
|
|
$
|
380,000
|
|
Total
|
|
$
|
2,825,000
|
|
|
$
|
435,000
|
|
|
$
|
1,733,123
|
|
|
$
|
1,297,110
|
|
|
$
|
380,000
|
|
(1)
|
Pursuant to the terms of the Services Agreement, our liability for severance owed to Messrs. Pearl and Griffie is capped at one year of base salary, which is the amount that would have been payable if such officers were subject to the Anadarko Officer Severance Plan. Although the amounts payable to Messrs. Ure, Collins, and Bourne under the Anadarko COC Plan are generally available to all WES employees, 100% of such amounts are included above because such amounts are not capped under the Services Agreement.
|
•
|
an annual retainer of $110,000 for each non-employee Board member;
|
•
|
an annual retainer of $2,000 for each member of the Audit Committee, or $17,000 for the Audit Committee chair;
|
•
|
an annual retainer of $2,000 for each member of the Special Committee, or $17,000 for the Special Committee chair;
|
•
|
a fee of $2,000 for each Board and committee meeting attended to the extent a non-employee Board member attends in excess of 10 total Board and committee meetings in one calendar year; and
|
•
|
annual grants of phantom units with a value of approximately $125,000 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 Occidental).
|
Name
|
|
Fees Earned or Paid in Cash
|
|
Stock Awards (1)
|
|
Option Awards
|
|
Non-Equity Incentive Plan Compensation
|
|
All Other Compensation
|
|
Total
|
||||||||||||
Thomas R. Hix
|
|
$
|
121,681
|
|
|
$
|
125,010
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
246,691
|
|
Craig W. Stewart
|
|
112,333
|
|
|
125,010
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
237,343
|
|
||||||
David J. Tudor
|
|
146,518
|
|
|
125,010
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
271,528
|
|
||||||
Steven D. Arnold
|
|
112,333
|
|
|
125,010
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
237,343
|
|
||||||
James R. Crane
|
|
112,333
|
|
|
125,010
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
237,343
|
|
||||||
Milton Carroll
|
|
79,989
|
|
|
125,010
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
204,999
|
|
(1)
|
The amounts included in the Stock Awards column represent the grant date fair value of non-option awards made to directors in 2019, computed in accordance with FASB ASC Topic 718. See the table below for phantom units awarded to each non-employee director during 2019.
|
Name
|
|
Grant Date
|
|
Phantom Units (#)
|
|
Grant Date Fair Value of Stock and Option Awards ($) (1)
|
||
Thomas R. Hix
|
|
May 8
|
|
4,202
|
|
|
125,010
|
|
Craig W. Stewart
|
|
May 8
|
|
4,202
|
|
|
125,010
|
|
David J. Tudor
|
|
May 8
|
|
4,202
|
|
|
125,010
|
|
Steven D. Arnold
|
|
May 8
|
|
4,202
|
|
|
125,010
|
|
James R. Crane
|
|
May 8
|
|
4,202
|
|
|
125,010
|
|
Milton Carroll
|
|
May 8
|
|
4,202
|
|
|
125,010
|
|
(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 2019 computed in accordance with FASB ASC Topic 718. These awards vested on August 8, 2019, as a result of Anadarko being acquired by Occidental pursuant to the Occidental Merger. The value ultimately realized by a director upon the actual vesting of the award(s) may or may not have been equal to the value included above.
|
•
|
each member of the Board of Directors;
|
•
|
each named executive officer of our general partner;
|
•
|
all directors and officers of our general partner as a group; and
|
•
|
Occidental and its affiliates.
|
Name and Address of Beneficial Owner (1)
|
|
Common
Units
Beneficially Owned (3)
|
|
Percentage of
Common Units
Beneficially
Owned
|
|
Occidental Petroleum Corporation (2)
|
|
242,136,976
|
|
|
54.5%
|
Glenn Vangolen
|
|
—
|
|
|
*
|
Michael P. Ure
|
|
—
|
|
|
*
|
Michael C. Pearl
|
|
1,250
|
|
|
*
|
Craig W. Collins
|
|
1,132
|
|
|
*
|
Robert W. Bourne
|
|
—
|
|
|
*
|
Charles G. Griffie
|
|
706
|
|
|
*
|
Marcia E. Backus
|
|
—
|
|
|
*
|
Peter J. Bennett
|
|
—
|
|
|
*
|
Oscar K. Brown
|
|
1,440
|
|
|
*
|
Jennifer M. Kirk
|
|
—
|
|
|
*
|
Steven D. Arnold
|
|
72,616
|
|
|
*
|
James R. Crane
|
|
254,201
|
|
|
*
|
Thomas R. Hix
|
|
18,530
|
|
|
*
|
Craig W. Stewart
|
|
30,073
|
|
|
*
|
David J. Tudor
|
|
31,241
|
|
|
*
|
Christopher B. Dial
|
|
—
|
|
|
*
|
Catherine A. Green
|
|
100
|
|
|
*
|
All directors and executive officers
as a group (17 persons)
|
|
411,289
|
|
|
*
|
*
|
Less than 1%
|
(1)
|
The address for Occidental and its representatives on the Board of Directors of our general partner is 5 Greenway Plaza, Suite 110, Houston, Texas 77046. The address for all other beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.
|
(2)
|
WGRI owns 161,319,520 common units, AMH owns 24,771,550 common units, WGRAH owns 38,139,260 common units, Kerr-McGee Worldwide Corporation owns 684,922 common units, and Anadarko E&P Onshore LLC owns 17,221,724 common units of WES. Occidental is the ultimate parent company of each of the foregoing entities and may, therefore, be deemed to beneficially own the units held by such entities.
|
(3)
|
Does not include unvested WES phantom unit awards as follows:
|
Name
|
|
Number of Units
|
||||
|
Time-Based Awards
|
|
TUR Awards
|
|
ROA Awards
|
|
Michael P. Ure
|
|
156,055
|
|
46,817
|
|
46,817
|
Michael C. Pearl
|
|
65,544
|
|
20,288
|
|
20,288
|
Craig W. Collins
|
|
65,544
|
|
20,288
|
|
20,288
|
Charles G. Griffie
|
|
40,575
|
|
12,485
|
|
12,485
|
Robert W. Bourne
|
|
37,454
|
|
10,924
|
|
10,924
|
Christopher B. Dial
|
|
34,333
|
|
9,364
|
|
9,364
|
Catherine A. Green
|
|
14,046
|
|
3,902
|
|
3,902
|
Title of Class
|
|
Name and Address of Beneficial Owner
|
|
Amount and
Nature
of Beneficial
Ownership
|
|
Percent of Class
|
Common Units
|
|
ALPS Advisors, Inc.
1290 Broadway, Suite 1100 Denver, CO 80203 |
|
24,153,629 (1)
|
|
5.33%
|
(1)
|
Based upon its Schedule 13G filed February 7, 2020, with the SEC with respect to Partnership securities held as of December 31, 2019, ALPS Advisors, Inc. (“ALPS”) has shared voting and dispositive power as to 24,153,629 common units and Alerian MLP ETF, a fund controlled by ALPS, also has shared voting and dispositive power as to 24,098,923 of the common units held by ALPS.
|
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
|
|
—
|
|
|
—
|
|
|
3,419,020
|
|
Equity compensation plans not approved by security holders
|
|
—
|
|
|
—
|
|
|
2,911,985
|
|
Total
|
|
—
|
|
|
—
|
|
|
6,331,005
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
General and administrative expenses
|
|
$
|
604
|
|
|
$
|
269
|
|
|
$
|
263
|
|
Public company expenses
|
|
4,089
|
|
|
2,895
|
|
|
1,821
|
|
|||
Total reimbursement
|
|
$
|
4,693
|
|
|
$
|
3,164
|
|
|
$
|
2,084
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
General and administrative expenses
|
|
$
|
84,039
|
|
|
$
|
35,077
|
|
|
$
|
31,733
|
|
Public company expenses
|
|
4,065
|
|
|
15,409
|
|
|
9,379
|
|
|||
Total reimbursement
|
|
$
|
88,104
|
|
|
$
|
50,486
|
|
|
$
|
41,112
|
|
•
|
Chipeta’s members will be required from time to time to make capital contributions to Chipeta to the extent approved by the members in connection with Chipeta’s annual budget;
|
•
|
Chipeta will distribute available cash, as defined in the Chipeta LLC agreement, if any, to its members quarterly in accordance with those members’ membership interests; and
|
•
|
Chipeta’s membership interests are subject to significant restrictions on transfer.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
Cash consideration paid
|
|
$
|
(425
|
)
|
|
$
|
(254
|
)
|
|
$
|
(3,910
|
)
|
Net carrying value
|
|
335
|
|
|
59,089
|
|
|
5,283
|
|
|||
Partners’ capital adjustment
|
|
$
|
(90
|
)
|
|
$
|
58,835
|
|
|
$
|
1,373
|
|
|
|
Year ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
Revenues and other (1)
|
|
$
|
1,607,396
|
|
|
$
|
1,353,711
|
|
|
$
|
1,539,105
|
|
Equity income, net – affiliates (1)
|
|
237,518
|
|
|
195,469
|
|
|
115,141
|
|
|||
Operating expenses
|
|
|
|
|
|
|
||||||
Cost of product (1)
|
|
254,771
|
|
|
168,535
|
|
|
74,560
|
|
|||
Operation and maintenance (1)
|
|
146,990
|
|
|
115,948
|
|
|
82,249
|
|
|||
General and administrative (2)
|
|
101,485
|
|
|
49,672
|
|
|
43,221
|
|
|||
Total operating expenses
|
|
503,246
|
|
|
334,155
|
|
|
200,030
|
|
|||
Interest income (3)
|
|
16,900
|
|
|
16,900
|
|
|
16,900
|
|
|||
Interest expense (4)
|
|
1,970
|
|
|
6,746
|
|
|
224
|
|
|||
APCWH Note Payable borrowings
|
|
11,000
|
|
|
321,780
|
|
|
98,813
|
|
|||
Repayment of APCWH Note Payable
|
|
439,595
|
|
|
—
|
|
|
—
|
|
|||
Settlement of the Deferred purchase price obligation – Anadarko (5)
|
|
—
|
|
|
—
|
|
|
(37,346
|
)
|
|||
Distributions to WES unitholders (6)
|
|
566,868
|
|
|
400,194
|
|
|
360,523
|
|
|||
Distributions to WES Operating unitholders (7)
|
|
19,768
|
|
|
7,583
|
|
|
7,100
|
|
|||
Above-market component of swap agreements with Anadarko
|
|
7,407
|
|
|
51,618
|
|
|
58,551
|
|
(1)
|
Represents amounts earned or incurred on and subsequent to the date of the acquisition of assets from Anadarko, and amounts earned or incurred by Anadarko on a historical basis for periods prior to the acquisition of such assets.
|
(2)
|
Represents general and administrative expense incurred on and subsequent to the date of the acquisition of assets from Anadarko, and a management services fee for expenses incurred by Anadarko for periods prior to the acquisition of such assets. These amounts include equity-based compensation expense allocated to us by Occidental (see LTIPs and Incentive Plans in Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K) and amounts charged by Occidental under the WES and WES Operating omnibus agreements.
|
(3)
|
Represents interest income recognized on the Anadarko note receivable.
|
(4)
|
Includes amounts related to finance leases and the APCWH Note Payable (see Note 1—Summary of Significant Accounting Policies and Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
|
(5)
|
Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation – Anadarko (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
|
(6)
|
Represents distributions paid to Occidental pursuant to our partnership agreement (see Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
|
(7)
|
Represents distributions paid to certain subsidiaries of Occidental pursuant to WES Operating’s partnership agreement (see Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
|
|
|
Year ended December 31,
|
||||||||||
thousands
|
|
2019
|
|
2018
|
|
2017
|
||||||
General and administrative (1)
|
|
$
|
99,613
|
|
|
$
|
48,819
|
|
|
$
|
42,411
|
|
Distributions to WES Operating unitholders (2)
|
|
1,025,931
|
|
|
514,906
|
|
|
452,777
|
|
(1)
|
Represents general and administrative expense incurred on and subsequent to the date of the acquisition of assets from Anadarko, and a management services fee for expenses incurred by Anadarko for periods prior to the acquisition of such assets. These amounts include equity-based compensation expense allocated to WES Operating by Occidental (see LTIPs and Incentive Plans in Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K) and amounts charged by Occidental pursuant to the WES Operating omnibus agreement.
|
(2)
|
Represents distributions paid to us and certain subsidiaries of Occidental pursuant to WES Operating’s partnership agreement (see Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). For the year ended December 31, 2019, includes distributions to us and a subsidiary of Occidental related to the repayment of the WGP RCF (see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
|
•
|
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.
|
|
|
WES
|
|
WES Operating
|
||||||||||||
thousands
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
Audit fees
|
|
$
|
325
|
|
|
$
|
235
|
|
|
$
|
1,862
|
|
|
$
|
1,860
|
|
Audit-related fees
|
|
25
|
|
|
—
|
|
|
375
|
|
|
210
|
|
||||
Total
|
|
$
|
350
|
|
|
$
|
235
|
|
|
$
|
2,237
|
|
|
$
|
2,070
|
|
Exhibit
Number |
|
Description
|
||
#
|
2.
|
1
|
|
|
|
3.
|
1
|
|
|
|
3.
|
2
|
|
|
|
3.
|
3
|
|
|
|
3.
|
4
|
|
|
|
3.
|
5
|
|
|
|
3.
|
6
|
|
|
|
3.
|
7
|
|
|
|
3.
|
8
|
|
|
|
3.
|
9
|
|
Exhibit
Number |
|
Description
|
||
|
3.
|
10
|
|
|
|
3.
|
11
|
|
|
|
3.
|
12
|
|
|
|
3.
|
13
|
|
|
|
3.
|
14
|
|
|
|
3.
|
15
|
|
|
|
3.
|
16
|
|
|
*
|
4.
|
1
|
|
|
|
4.
|
2
|
|
|
|
4.
|
3
|
|
|
|
4.
|
4
|
|
|
|
4.
|
5
|
|
|
|
4.
|
6
|
|
|
|
4.
|
7
|
|
|
|
4.
|
8
|
|
|
|
4.
|
9
|
|
|
|
4.
|
10
|
|
|
|
4.
|
11
|
|
Exhibit
Number |
|
Description
|
||
|
4.
|
12
|
|
|
|
4.
|
13
|
|
|
|
4.
|
14
|
|
|
|
4.
|
15
|
|
|
|
4.
|
16
|
|
|
|
4.
|
17
|
|
|
|
4.
|
18
|
|
|
|
4.
|
19
|
|
|
|
4.
|
20
|
|
|
|
4.
|
21
|
|
|
|
4.
|
22
|
|
|
|
4.
|
23
|
|
|
|
4.
|
24
|
|
|
|
10.
|
1
|
|
|
|
10.
|
2
|
|
|
|
10.
|
3
|
|
Exhibit
Number |
|
Description
|
||
|
10.
|
4
|
|
|
|
10.
|
5
|
|
|
|
10.
|
6
|
|
|
|
10.
|
7
|
|
|
|
10.
|
8
|
|
|
|
10.
|
9
|
|
|
|
10.
|
10
|
|
|
‡
|
10.
|
11
|
|
|
‡
|
10.
|
12
|
|
|
|
10.
|
13
|
|
|
|
10.
|
14
|
|
|
|
10.
|
15
|
|
|
‡
|
10.
|
16
|
|
|
‡
|
10.
|
17
|
|
|
‡
|
10.
|
18
|
|
|
‡
|
10.
|
19
|
|
|
‡
|
10.
|
20
|
|
|
‡
|
10.
|
21
|
|
Exhibit
Number |
|
Description
|
||
‡
|
10.
|
22
|
|
|
‡
|
10.
|
23
|
|
|
‡
|
10.
|
24
|
|
|
†
|
10.
|
25
|
|
|
|
10.
|
26
|
|
|
|
10.
|
27
|
|
|
|
10.
|
28
|
|
|
|
10.
|
29
|
|
|
|
10.
|
30
|
|
|
|
10.
|
31
|
|
|
|
10.
|
32
|
|
|
|
10.
|
33
|
|
|
|
10.
|
34
|
|
|
|
10.
|
35
|
|
|
|
10.
|
36
|
|
|
|
10.
|
37
|
|
*
|
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 have been omitted as confidential pursuant to Item 601(b)(10) of Regulation S-K or a request for confidential treatment.
|
‡
|
Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.
|
|
WESTERN MIDSTREAM PARTNERS, LP
|
|
|
February 27, 2020
|
|
|
/s/ Michael C. Pearl
|
|
Michael C. Pearl
Senior Vice President and Chief Financial Officer Western Midstream Holdings, LLC (as general partner of Western Midstream Partners, LP) |
|
|
|
|
|
WESTERN MIDSTREAM OPERATING, LP
|
February 27, 2020
|
|
|
|
|
/s/ Michael C. Pearl
|
|
Michael C. Pearl
Senior Vice President and Chief Financial Officer
Western Midstream Operating GP, LLC
(as general partner of Western Midstream Operating, LP)
|
Signature
|
Title (Position with Western Midstream Holdings, LLC)
|
|
|
/s/ Glenn Vangolen
|
Chairman
|
Glenn Vangolen
|
|
|
|
/s/ Michael P. Ure
|
President, Chief Executive Officer and Director
|
Michael P. Ure
|
(Principal Executive Officer)
|
|
|
/s/ Michael C. Pearl
|
Senior Vice President and Chief Financial Officer
|
Michael C. Pearl
|
(Principal Financial Officer)
|
|
|
/s/ Catherine A. Green
|
Vice President and Chief Accounting Officer
|
Catherine A. Green
|
(Principal Accounting Officer)
|
|
|
/s/ Marcia E. Backus
|
Director
|
Marcia E. Backus
|
|
|
|
/s/ Peter J. Bennett
|
Director
|
Peter J. Bennett
|
|
|
|
/s/ Oscar K. Brown
|
Director
|
Oscar K. Brown
|
|
|
|
/s/ Jennifer M. Kirk
|
Director
|
Jennifer M. Kirk
|
|
|
|
/s/ Steven D. Arnold
|
Director
|
Steven D. Arnold
|
|
|
|
/s/ James R. Crane
|
Director
|
James R. Crane
|
|
|
|
/s/ Thomas R. Hix
|
Director
|
Thomas R. Hix
|
|
|
|
/s/ Craig W. Stewart
|
Director
|
Craig W. Stewart
|
|
|
|
/s/ David J. Tudor
|
Director
|
David J. Tudor
|
|
•
|
surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;
|
•
|
special charges for services requested by a unitholder; and
|
•
|
other similar fees or charges.
|
•
|
represents that the transferee has the capacity, power and authority to become bound by our Partnership Agreement;
|
•
|
automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our Partnership Agreement; and
|
•
|
is deemed to have given the consents and approvals contained in our Partnership Agreement.
|
•
|
enlarge the obligations of any Limited Partner without its consent, unless approved by at least a majority of the type or class of Limited Partner Interests so affected, or
|
•
|
enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our General Partner or any of its Affiliates without the consent of our General Partner, which may be given or withheld in its sole discretion.
|
•
|
first, towards the payment of all of our creditors and the settlement of or creation of a reserve for contingent liabilities; and
|
•
|
then, to all Partners in accordance with the positive balance in the respective Capital Accounts.
|
•
|
to remove or replace our General Partner,
|
•
|
to approve some amendments to our Partnership Agreement, or
|
•
|
to take other action under our Partnership Agreement,
|
•
|
our General Partner,
|
•
|
any Departing General Partner,
|
•
|
any person who is or was an Affiliate of our General Partner or any Departing General Partner,
|
•
|
any person who is or was a member, partner, officer, director, employee, agent or trustee of our General Partner or any Departing General Partner or any Affiliate of our General Partner or any Departing General Partner,
|
•
|
any person who is or was serving at the request of our General Partner or any Departing General Partner or any Affiliate of our General Partner or any Departing General Partner as an officer, director, employee, member, partner, agent or trustee of another person, or
|
•
|
any person designated by our General Partner.
|
•
|
a current list of the name and last known address of each partner,
|
•
|
a copy of our tax returns,
|
•
|
information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner,
|
•
|
copies of our Partnership Agreement, the certificate of limited partnership of the partnership, related amendments and powers of attorney under which they have been executed;
|
•
|
information regarding the status of our business and financial condition; and
|
•
|
any other information regarding our affairs as is just and reasonable.
|
•
|
less, the amount of cash reserves established by our General Partner to:
|
•
|
provide for the proper conduct of our business;
|
•
|
permit OLP GP to make Capital Contributions to OLP if we choose to maintain our 2.0% General Partner Interest upon the issuance of additional partnership securities by OLP;
|
•
|
comply with applicable law, any of our debt instruments or other agreements; or
|
•
|
provide funds for distributions to our unitholders for any one or more of the next four Quarters;
|
•
|
plus, if our General Partner so determines, all or a portion of cash on hand on the date of determination of Available Cash for the Quarter resulting from working capital borrowings made after the end of the Quarter.
|
•
|
provide for the proper conduct of our business;
|
•
|
permit OLP GP to make Capital Contributions to OLP to maintain its 2.0% General Partner Interest upon the issuance of partnership securities by OLP;
|
•
|
comply with applicable law, any of our future debt instruments or other agreements, if any; or
|
•
|
provide funds for distributions to our unitholders for any one or more of the next four Quarters.
|
•
|
the level of capital expenditures it makes;
|
•
|
the level of its operating and maintenance and general and administrative costs;
|
•
|
its debt service requirements and other liabilities;
|
•
|
fluctuations in its working capital needs;
|
•
|
its ability to borrow funds and access capital markets;
|
•
|
its treatment as a flow-through entity for U.S. federal income tax purposes;
|
•
|
restrictions contained in debt agreements to which it is a party; and
|
•
|
the amount of cash reserves established by OLP GP.
|
•
|
Our existing debt agreements contain certain financial tests and covenants that we have to satisfy. If we are unable to satisfy the restrictions under any future debt agreements, we could be prohibited from making a distribution to you notwithstanding our stated distribution policy.
|
•
|
Our General Partner will have the authority to establish reserves for the prudent conduct of their respective businesses and for future cash distributions to our unitholders, respectively. The establishment or increase of those reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy, as well as the distributions we expect to receive from OLP. Any determination to establish cash reserves made by our General Partner in good faith will be binding on our unitholders. Our Partnership Agreement provides that in order for a determination by our General Partner to be made in good faith, our General Partner must believe that the determination is in our best interests.
|
•
|
If OLP is unable to comply with current and future restrictions under its debt agreements, OLP could be prohibited from making cash distributions to us, which in turn would prevent us from making cash distributions to you notwithstanding our stated distribution policy. OLP may in the future enter into other debt arrangements containing restrictions on making cash distributions.
|
•
|
While our Partnership Agreement requires us to distribute all of our Available Cash, our Partnership Agreement, including the provisions requiring us to make cash distributions contained therein, may be amended by a vote of holders of a majority of our Common Units. Occidental currently owns an aggregate of 54.5% of our Common Units.
|
•
|
We may lack sufficient cash to pay distributions to our unitholders due to increases in our or OLP’s operating or general and administrative expenses, principal and interest payments on debt, tax expenses, working capital requirements and anticipated cash needs of us or OLP and its subsidiaries.
|
(A)
|
the sum of (1) the Executive’s Annual Base Salary through the Date of Termination to the extent not theretofore paid, (2) the product of (x) the higher of (I) the highest annual bonus earned by the Executive for the last three fiscal years prior to the Change of Control Date and (II) the Annual Bonus paid or payable for the most recently completed fiscal year during the Employment Period, in each case, including any bonus or portion thereof which has been earned but deferred (and annualized for any fiscal year consisting of less than twelve full months or during which the Executive was employed for less than twelve full months) (such higher amount being referred to as the “Highest Annual Bonus”) and (y) a fraction, the numerator of which is the number of days in the current fiscal year through the Date of Termination, and the denominator of which is 365, and (3) any accrued paid time off, to the extent not theretofore used or paid (the sum of the amounts described in clauses (1), (2), and (3) shall be hereinafter referred to as the “Accrued Obligations”); and
|
(B)
|
an amount equal to the product of (1) two and (2) the sum of (x) the Executive’s Annual Base Salary and (y) the Highest Annual Bonus; and
|
(C)
|
an amount equal to the total value of the Executive’s Account (as defined in the Company’s Savings Restoration Plan (the “SRP”)), with such amount being the higher of (1) the value of the Executive’s Account on the Executive’s Date of Termination or (2) the value of the Executive’s Account on the Change of Control Date, in each case with “value” determined under the applicable change of control provisions in the SRP, if any. The amount payable under this Section 6(a)(i)(C) shall represent the payment of the amount due to the Executive under the SRP, and shall not be duplicative thereof. Notwithstanding the above provisions of this Section 6(a)(i)(C), the Company shall pay the lump sum cash payment as set forth herein above only if such payment would not be considered to be an impermissible acceleration of benefits under the SRP under Code Section 409A. In the event that the payment of the benefits payment
|
(D)
|
an amount equal to the additional Company matching contributions which would have been made on the Executive’s behalf in the Company’s Employee Savings Plan (the “ESP”) (assuming continued participation on the same basis as immediately prior to the Change of Control Date), plus the additional amount of any benefit the Executive would have accrued under the SRP as a result of contribution limitations in the ESP, for the 24-month period beginning on the Date of Termination (with the Company’s matching contributions being determined pursuant to the applicable provisions of the ESP and the SRP and based upon the Executive’s compensation (including any amounts deferred pursuant to any deferred compensation program) in effect for the 12-month period immediately prior to the Change of Control Date); and
|
(E)
|
an amount equal to the sum of the present values, as of the Date of Termination, of (1) the accrued retirement benefit payable under the Company’s Retirement Restoration Plan (or, if the Executive participates in another plan that, in the sole determination of the Company, is intended to provide benefits similar to those under the Company’s Retirement Restoration Plan, such other plan) (each referred to herein as the “RRP”) and (2) the additional retirement benefits that the Executive would have accrued under the tax-qualified defined benefit plan of the Company or any Affiliate in which the Executive participates (the “Retirement Plan”) and the RRP if the Executive had continued employment until the expiration of the two-year period following the Date of Termination (assuming that the Executive’s compensation in each of the additional years is that required by Section 4(b)(i) and Section 4(b)(ii) hereof), with the present values being computed by discounting to the Date of Termination the accrued benefit and the additional retirement benefits payable as lump sums at an assumed benefit commencement date of the later of (i) the date the Executive attains age 55 and (ii) the date two years after the Date of Termination, at the rate of interest used for valuing lump-sum payments in excess of $25,000 for participants with retirement benefits commencing immediately under the Retirement Plan, as in effect as of the Change of Control Date with such amount to be fully offset and reduced by the amount of any
|
|
EXECUTIVE
|
||
|
|
||
|
By:
|
/s/ Michael C. Pearl
|
|
|
Name:
|
Michael C. Pearl
|
|
|
Date:
|
July 23, 2013
|
|
|
|
|
|
|
ANADARKO PETROLEUM CORPORATION
|
||
|
|
|
|
|
By:
|
/s/ Julia A. Struble
|
|
|
Name:
|
Julia A. Struble
|
|
|
Title:
|
VP, Human Resources
|
|
|
Date:
|
July 29, 2013
|
|
ANADARKO PETROLEUM CORPORATION
|
||
|
|
||
|
By:
|
/s/ Amanda M. McMillian
|
|
|
Name:
|
Amanda M. McMillian
|
|
|
Title:
|
EVP and General Counsel
|
|
|
|
|
|
|
MICHAEL PEARL
|
||
|
|
/s/ Michael Pearl
|
(A)
|
the sum of (1) the Executive’s Annual Base Salary through the Date of Termination to the extent not theretofore paid, (2) the product of (x) the higher of (I) the highest annual bonus earned by the Executive for the last three fiscal years prior to the Change of Control Date and (II) the Annual Bonus paid or payable for the most recently completed fiscal year during the Employment Period, in each case, including any bonus or portion thereof which has been earned but deferred (and annualized for any fiscal year consisting of less than twelve full months or during which the Executive was employed for less than twelve full months) (such higher amount being referred to as the “Highest Annual Bonus”) and (y) a fraction, the numerator of which is the number of days in the current fiscal year through the Date of Termination, and the denominator of which is 365, and (3) any accrued paid time off, to the extent not theretofore used or paid (the sum of the amounts described in clauses (1), (2), and (3) shall be hereinafter referred to as the “Accrued Obligations”); and
|
(B)
|
an amount equal to the product of (1) two and (2) the sum of (x) the Executive’s Annual Base Salary and (y) the Highest Annual Bonus; and
|
(C)
|
an amount equal to the total value of the Executive’s Account (as defined in the Company’s Savings Restoration Plan (the “SRP”)), with such amount being the higher of (1) the value of the Executive’s Account on the Executive’s Date of Termination or (2) the value of the Executive’s Account on the Change of Control Date, in each case with “value” determined under the applicable change of control provisions in the SRP, if any. The amount payable under this Section 6(a)(i)(C) shall represent the payment of the amount due to the Executive under the SRP, and shall not be duplicative thereof. Notwithstanding the above provisions of this Section 6(a)(i)(C), the Company shall pay the lump sum cash payment as set forth herein above only if such payment would not be considered to be an impermissible acceleration of benefits under the SRP under Code Section 409A. In the event that the payment of the benefits payment
|
(D)
|
an amount equal to the additional Company matching contributions which would have been made on the Executive’s behalf in the Company’s Employee Savings Plan (the “ESP”) (assuming continued participation on the same basis as immediately prior to the Change of Control Date), plus the additional amount of any benefit the Executive would have accrued under the SRP as a result of contribution limitations in the ESP, for the 24-month period beginning on the Date of Termination (with the Company’s matching contributions being determined pursuant to the applicable provisions of the ESP and the SRP and based upon the Executive’s compensation (including any amounts deferred pursuant to any deferred compensation program) in effect for the 12-month period immediately prior to the Change of Control Date); and
|
(E)
|
an amount equal to the sum of the present values, as of the Date of Termination, of (1) the accrued retirement benefit payable under the Company’s Retirement Restoration Plan (or, if the Executive participates in another plan that, in the sole determination of the Company, is intended to provide benefits similar to those under the Company’s Retirement Restoration Plan, such other plan) (each referred to herein as the “RRP”) and (2) the additional retirement benefits that the Executive would have accrued under the tax-qualified defined benefit plan of the Company or any Affiliate in which the Executive participates (the “Retirement Plan”) and the RRP if the Executive had continued employment until the expiration of the two-year period following the Date of Termination (assuming that the Executive’s compensation in each of the additional years is that required by Section 4(b)(i) and Section 4(b)(ii) hereof), with the present values being computed by discounting to the Date of Termination the accrued benefit and the additional retirement benefits payable as lump sums at an assumed benefit commencement date of the later of (i) the date the Executive attains age 55 and (ii) the date two years after the Date of Termination, at the rate of interest used for valuing lump-sum payments in excess of $25,000 for participants with retirement benefits commencing immediately under the Retirement Plan, as in effect as of the Change of Control Date with such amount to be fully offset and reduced by the amount of any
|
|
EXECUTIVE
|
||
|
|
||
|
By:
|
/s/ Charles Griffie
|
|
|
Name:
|
Charles Griffie
|
|
|
Date:
|
December 5, 2018
|
|
|
|
|
|
|
ANADARKO PETROLEUM CORPORATION
|
||
|
|
|
|
|
By:
|
/s/ Joe Mongrain
|
|
|
Name:
|
Joe Mongrain
|
|
|
Title:
|
VP, Human Resources
|
|
|
Date:
|
December 12, 2018
|
|
ANADARKO PETROLEUM CORPORATION
|
||
|
|
||
|
By:
|
/s/ Amanda M. McMillian
|
|
|
Name:
|
Amanda M. McMillian
|
|
|
Title:
|
EVP and General Counsel
|
|
|
|
|
|
|
CHARLES GRIFFIE
|
||
|
|
/s/ Charles Griffie
|
|
WESTERN MIDSTREAM HOLDINGS, LLC
|
||
|
|
|
|
|
By:
|
|
|
|
|
Name:
|
|
|
|
Title:
|
|
|
|
|
Hereunto duly authorized
|
|
|
|
|
|
INDEMNITEE:
|
||
|
|
|
|
|
|
Name:
|
|
|
|
Title:
|
3.
|
A new Section 3(F) is added to the Commercial Terms as follows:
|
SHIPPER:
|
|
|
|
Notices:
|
Kerr-McGee Oil and Gas Onshore LP
|
|
5 Greenway Plaza, Suite 110
|
|
Houston, Texas 77046-0521
|
|
Attn: OMSD Midstream Commercial Operations
|
|
Facsimile: 713-985-1440
|
|
Email: contract-notices@oxy.com
|
|
|
With a copy to:
|
Kerr-McGee Oil and Gas Onshore LP
|
|
5 Greenway Plaza, Suite 110
|
|
Houston, Texas 77046-0521
|
|
Attn: Assistant General Counsel, Oxy Energy Services, LLC
|
|
Facsimile: 713-985-1440
|
GATHERER
|
|
SHIPPER
|
||
|
|
|
|
|
KERR-MCGEE GATHERING LLC
|
|
KERR-MCGEE OIL & GAS ONSHORE LP
|
||
|
|
|
|
|
|
|
|
By: Oxy Midstream Strategic Development, LLC,
its Agent
|
|
|
|
|
|
|
By:
|
/s/ Craig W. Collins
|
|
By:
|
/s/ Frederick A. Forthuber
|
Name:
|
Craig W. Collins
|
|
Name:
|
Frederick A. Forthuber
|
Title:
|
Senior Vice President & Chief Operating Officer
|
|
Title:
|
Authorized Representative
|
|
Year 1
|
Year 2
|
Year 3
|
Year 4
|
Year 5
|
Year 6
|
Year 7
|
Year 8
|
Year 9
|
Year 10
|
Month 1
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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Month 2
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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Month 3
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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Month 4
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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Month 5
|
[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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Month 6
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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Month 7
|
[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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Month 8
|
[***]
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[***]
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[***]
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[***]
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[***]
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[***]
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[***]
|
[***]
|
[***]
|
[***]
|
Month 9
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
Month 10
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
Month 11
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
Month 12
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
|
Year 1
|
Year 2
|
Year 3
|
Year 4
|
Year 5
|
Year 6
|
Year 7
|
Year 8
|
Year 9
|
Year 10
|
Month 1
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
Month 2
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
Month 3
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
Month 4
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
Month 5
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
Month 6
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
Month 7
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
Month 8
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
Month 9
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
Month 10
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
Month 11
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
Month 12
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
[***]
|
1.
|
I have reviewed this annual report on Form 10-K of Western Midstream 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/ Michael P. Ure
|
|
Michael P. Ure
President and Chief Executive Officer
Western Midstream Holdings, LLC
(as general partner of Western Midstream Partners, LP)
|
1.
|
I have reviewed this annual report on Form 10-K of Western Midstream 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/ Michael C. Pearl
|
|
Michael C. Pearl
Senior Vice President and Chief Financial Officer
Western Midstream Holdings, LLC (as general partner of Western Midstream Partners, LP) |
1.
|
I have reviewed this annual report on Form 10-K of Western Midstream Operating, 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/ Michael P. Ure
|
|
Michael P. Ure
President and Chief Executive Officer
Western Midstream Operating GP, LLC
(as general partner of Western Midstream Operating, LP)
|
1.
|
I have reviewed this annual report on Form 10-K of Western Midstream Operating, 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/ Michael C. Pearl
|
|
Michael C. Pearl
Senior Vice President and Chief Financial Officer
Western Midstream Operating GP, LLC (as general partner of Western Midstream Operating, LP) |
(1)
|
the Annual Report on Form 10-K of the Partnership for the period ending December 31, 2019, 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 27, 2020
|
|
|
|
|
|
|
|
/s/ Michael P. Ure
|
|
|
Michael P. Ure
President and Chief Executive Officer
Western Midstream Holdings, LLC
(as general partner of Western Midstream Partners, LP)
|
|
|
|
February 27, 2020
|
|
|
|
|
|
|
|
/s/ Michael C. Pearl
|
|
|
Michael C. Pearl
Senior Vice President and Chief Financial Officer
Western Midstream Holdings, LLC
(as general partner of Western Midstream Partners, LP)
|
(1)
|
the Annual Report on Form 10-K of the Partnership for the period ending December 31, 2019, 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 27, 2020
|
|
|
|
|
|
|
|
/s/ Michael P. Ure
|
|
|
Michael P. Ure
President and Chief Executive Officer
Western Midstream Operating GP, LLC
(as general partner of Western Midstream Operating, LP)
|
|
|
|
February 27, 2020
|
|
|
|
|
|
|
|
/s/ Michael C. Pearl
|
|
|
Michael C. Pearl
Senior Vice President and Chief Financial Officer
Western Midstream Operating GP, LLC
(as general partner of Western Midstream Operating, LP)
|