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FORM 10-K
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x
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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 SECURITIES EXCHANGE ACT OF 1934
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Black Stone Minerals, L.P.
(Exact Name of Registrant As Specified in Its Charter)
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Delaware
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47-1846692
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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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1001 Fannin Street, Suite 2020
Houston, Texas
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77002
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(Address of Principal Executive Offices)
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(Zip Code)
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Title of each class
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Name of each exchange on which registered
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Common Units Representing Limited Partner Interests
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act: None
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Large Accelerated Filer
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x
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Accelerated Filer
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¨
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Non-Accelerated Filer
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¨
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(Do not check if a smaller reporting company)
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Smaller Reporting Company
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¨
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Emerging Growth Company
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¨
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PAGE
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•
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our ability to execute our business strategies;
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the volatility of realized oil and natural gas prices;
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the level of production on our properties;
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•
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the overall supply and demand for oil and natural gas, and regional supply and demand factors, delays, or interruptions of production;
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our ability to replace our oil and natural gas reserves;
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our ability to identify, complete, and integrate acquisitions;
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general economic, business, or industry conditions;
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competition in the oil and natural gas industry;
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•
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the ability of our operators to obtain capital or financing needed for development and exploration operations;
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title defects in the properties in which we invest;
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the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;
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restrictions on the use of water for hydraulic fracturing;
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the availability of pipeline capacity and transportation facilities;
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the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
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federal and state legislative and regulatory initiatives relating to hydraulic fracturing;
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future operating results;
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future cash flows and liquidity, including our ability to generate sufficient cash to pay quarterly distributions;
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exploration and development drilling prospects, inventories, projects, and programs;
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operating hazards faced by our operators;
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the ability of our operators to keep pace with technological advancements; and
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certain factors discussed elsewhere in this Annual Report.
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Nonparticipating royalty interests
(“NPRIs”), which are royalty interests that are carved out of the mineral estate and represent the right, which is typically perpetual, to receive a fixed, cost-free percentage of production or revenue from production, without an associated right to lease or receive lease bonus; and
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Overriding royalty interests
(“ORRIs”), which are royalty interests that burden working interests and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease. ORRIs remain in effect until the associated leases expire.
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Acreage as of December 31, 2017
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Average Daily Production (Boe/d)
For the Year Ended December 31, 2017
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||||||||||||||
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Mineral and Royalty Interests
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Working Interests
1
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|||||||||||||
USGS Petroleum Province
2
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Mineral Interests
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NPRIs
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ORRIs
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Gross
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Net
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||||||||
Louisiana-Mississippi Salt Basins
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5,408,632
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238,426
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26,104
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59,117
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7,999
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4,752
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Western Gulf (onshore)
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1,732,750
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297,303
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282,208
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122,167
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18,692
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5,561
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Permian Basin
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1,647,573
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800,654
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185,069
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8,113
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5,051
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2,820
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Williston Basin
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1,543,797
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65,974
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34,099
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59,875
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7,895
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3,624
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Palo Duro Basin
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1,024,913
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22,791
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1,120
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—
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—
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87
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East Texas Basin
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598,717
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55,155
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78,960
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148,121
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50,693
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13,704
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Anadarko Basin
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577,264
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13,723
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280,283
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30,939
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21,254
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1,652
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Appalachian Basin
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495,843
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416
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14,861
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—
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—
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853
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Arkoma Basin
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357,394
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9,999
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38,109
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9,045
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2,333
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1,337
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Bend Arch-Fort Worth Basin
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149,260
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56,703
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43,514
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52,885
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13,475
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353
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Southwestern Wyoming
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22,338
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—
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77,529
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14,056
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2,050
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483
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Other
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3,235,453
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314,539
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1,033,649
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39,152
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8,742
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1,785
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Total
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16,793,934
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1,875,683
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2,095,505
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543,470
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138,184
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37,011
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1
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Excludes acreage for which we have incomplete seller records.
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2
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The basins and regions shown in the table are consistent with U.S. Geological Survey (“USGS”) delineations of petroleum provinces of onshore and state offshore areas in the continental United States. We refer to these petroleum provinces as “basins” or “regions.”
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Louisiana-Mississippi Salt Basins.
The Louisiana-Mississippi Salt Basins region ranges from northern Louisiana and southern Arkansas through south central and southern Mississippi, southern Alabama, and the Florida Panhandle. The Haynesville/Bossier plays, which have been extensively delineated through drilling, are the most prospective and most active unconventional plays for natural gas production and reserves within this region. Approximately half of the Haynesville/Bossier plays’ prospective acreage is within the Louisiana-Mississippi Salt Basins region, where we own significant mineral and royalty interests and working interests. There are a number of additional conventional and unconventional plays in this region in which we hold considerable mineral and royalty interests, including the Brown Dense, Cotton Valley, Hosston, Norphlet, Smackover, Tuscaloosa Marine Shale, and Wilcox plays.
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•
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Western Gulf (onshore).
The Western Gulf region, which ranges from South Texas through southeastern Louisiana, includes a variety of both conventional and unconventional plays. We have extensive exposure to the Eagle Ford Shale in South Texas, where we are experiencing a significant level of development drilling on our mineral interests within the oil and rich-gas and condensate areas of the play. In addition to the Eagle Ford Shale play, there are a number of other conventional and unconventional plays to which we have exposure to in the region, including the Austin Chalk, Buda, Eaglebine (or Maness) Shale, Frio, Glenrose, Olmos, Woodbine, Vicksburg, Wilcox, and Yegua plays.
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Permian Basin.
The Permian Basin ranges from southeastern New Mexico into West Texas and is currently one of the most active areas for drilling in the United States. It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west, and the Central Basin Platform in between. Our acreage underlies prospective areas for the Wolfcamp play in the Midland and Delaware Basins, the Spraberry formation in the Midland Basin, and the Bone Spring formation in the Delaware Basin, which are among the plays most actively targeted by drillers within the basin. In addition to these plays, we own mineral and royalty interests that are prospective for a number of other conventional and unconventional plays in the Permian Basin, including the Atoka, Clearfork, Ellenberger, San Andres, Strawn, and Wichita Albany plays.
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Williston Basin.
The Williston Basin stretches through the western half of North Dakota, the northwest part of South Dakota, and eastern Montana and includes plays such as the Bakken/Three Forks plays, where we have significant exposure through our mineral and royalty interests as well as through our working interests. We are also exposed to other well-known plays in the basin, including the Duperow, Mission Canyon, Madison, Ratcliff, Red River, and Spearfish plays.
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Palo Duro Basin.
The Palo Duro Basin covers much of the Texas Panhandle but also occupies a small portion of the Oklahoma Panhandle and extends partially into New Mexico to the west. We have a significant acreage position in the Palo Duro Basin, much of which underlies an unconventional oil play in the Canyon Lime. We are also well positioned relative to a number of other conventional and unconventional plays in the Palo Duro Basin, including the Brown Dolomite, Canyon Wash, Cisco Sand, and Strawn Wash plays.
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East Texas Basin.
The East Texas Basin ranges from central East Texas to northeast Texas and includes the Haynesville/Bossier plays and the Cotton Valley play, which are among the most prolific natural gas plays in the basin. We own a material acreage position in the southern Shelby Trough area of the Haynesville/Bossier plays located in San Augustine, Nacogdoches, and Angelina Counties, which is one of the most active areas being drilled today for that play in the East Texas Basin. There are other active plays to which we have significant exposure, including the Bossier Sand, Goodland Lime, James Lime, Pettit, Travis Peak, Smackover, and Woodbine plays.
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•
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Anadarko Basin.
The Anadarko Basin encompasses the Texas Panhandle, southeastern Colorado, southwestern Kansas, and western Oklahoma. We own mineral and royalty interests as well as working interests in prospective areas for most of the prolific plays in this basin, including the Granite Wash, Atoka, Cleveland, Meramac, and Woodford Shale plays. Other plays in which we hold interests in prospective acreage include the Cottage Grove, Hogshooter, Marmaton, Springer, and Tonkawa plays.
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•
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Appalachian Basin.
The Appalachian Basin covers most of Pennsylvania, eastern Ohio, West Virginia, western Maryland, eastern Kentucky, central Tennessee, western Virginia, northwestern Georgia, and northern Alabama. The basin’s most active plays in which we have acreage are the Marcellus Shale and Utica plays, which cover most of western Pennsylvania, northern West Virginia, and eastern Ohio. In addition to the Marcellus Shale, there are a number of other conventional and unconventional plays to which we have material exposure in the Appalachian Basin, including the Berea, Big Injun, Devonian, Huron, Rhinestreet, and Utica plays.
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•
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Arkoma Basin.
The Arkoma Basin stretches from southeast Oklahoma through central Arkansas. The Fayetteville Shale play is one of the basin’s most significant unconventional natural gas plays. We own material mineral and royalty interests within the prospective area of the Fayetteville Shale. In addition, we have exposure to a number of other conventional and unconventional plays in the basin, including the Atoka, Cromwell, Dunn, Hale, and Woodford Shale plays.
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•
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Bend Arch-Fort Worth Basin.
The Bend Arch-Fort Worth Basin covers much of north central Texas and includes the Barnett Shale play as its most active unconventional play. Through our mineral and royalty interests in this basin, we have significant exposure to the Barnett Shale as well as a number of other active conventional and unconventional plays in the basin, including the Bend Conglomerate, Caddo, Marble Falls, and Mississippian Lime plays.
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•
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Southwestern Wyoming.
The Southwestern Wyoming region covers most of southern and western Wyoming. The Pinedale Anticline is one of the region’s largest producing fields and mainly produces from the Lance formation. We have a meaningful position in the Pinedale Anticline, and we have interests prospective for other plays as well, including the Mesaverde, Niobrara, and Wasatch plays.
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As of December 31, 2017
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Average Daily Production (Boe/d) for the Year Ended December 31,
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||||||||||||||
USGS Petroleum Province
1
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Acres
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Average Ownership Interest
2
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Average Ownership Leased
3
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2017
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2016
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2015
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||||||
Louisiana-Mississippi Salt Basins
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5,408,632
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53.3
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%
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8.7
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%
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3,867
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|
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3,415
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|
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3,384
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Western Gulf (onshore)
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1,732,750
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52.7
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%
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36.0
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%
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4,668
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|
|
4,526
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5,021
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Permian Basin
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1,647,573
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11.6
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%
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79.2
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%
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2,443
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|
1,035
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|
585
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Williston Basin
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1,543,797
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14.6
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%
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44.7
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%
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2,906
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|
|
2,534
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2,430
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Palo Duro Basin
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1,024,913
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46.2
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%
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8.7
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%
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|
75
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|
|
24
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23
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East Texas Basin
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598,717
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53.0
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%
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32.3
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%
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3,098
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|
|
1,854
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|
884
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Black Warrior Basin
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594,906
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54.6
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%
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2.3
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%
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|
38
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|
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—
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39
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Anadarko Basin
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577,264
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|
|
31.7
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%
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61.8
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%
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|
745
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|
|
673
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|
|
959
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Eastern Great Basin
|
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567,909
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|
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96.7
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%
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|
0.1
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%
|
|
—
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|
39
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|
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—
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Appalachian Basin
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495,843
|
|
|
39.4
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%
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|
15.3
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%
|
|
191
|
|
|
163
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|
|
80
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Arkoma Basin
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357,394
|
|
|
52.9
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%
|
|
31.6
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%
|
|
1,172
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|
|
1,302
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|
|
1,458
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Western Great Basin
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338,303
|
|
|
90.5
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%
|
|
—
|
|
|
—
|
|
|
—
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|
|
—
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North-Central Montana
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|
182,868
|
|
|
13.5
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%
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|
32.5
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%
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3
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|
|
9
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|
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4
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Piedmont
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179,879
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|
|
67.8
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%
|
|
—
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|
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—
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|
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—
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—
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Atlantic Coastal Plain
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171,791
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12.5
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%
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31.7
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%
|
|
—
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|
199
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|
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—
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Bend Arch-Fort Worth Basin
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149,260
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20.8
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%
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34.7
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%
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|
198
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|
|
—
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|
|
392
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|
Cherokee Platform
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112,384
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13.8
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%
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33.6
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%
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26
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|
|
34
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|
|
41
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Florida Peninsula
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90,744
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|
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12.1
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%
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47.6
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%
|
|
—
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|
|
2
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|
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—
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Illinois Basin
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80,864
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|
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53.1
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%
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8.0
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%
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|
2
|
|
|
3
|
|
|
2
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Powder River Basin
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80,239
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|
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11.2
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%
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26.7
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%
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|
6
|
|
|
—
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|
|
56
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Other
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857,904
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|
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30.6
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%
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27.2
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%
|
|
967
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|
|
1,295
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|
|
301
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Total
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16,793,934
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43.4
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%
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26.4
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%
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|
20,405
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|
|
17,107
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15,659
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1
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The basins and regions shown in the table are consistent with USGS petroleum-province delineations.
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2
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Ownership interest is equal to the percentage that our undivided ownership interest in a tract bears to the entire tract. The average ownership interests shown reflects the weighted averages of our ownership interests in all tracts in the basin or region. Our weighted-average mineral royalty for all of our mineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average royalty interest in our mineral and royalty interests.
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3
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The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the basin or region.
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As of December 31, 2017
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Average Daily Production (Boe/d) for the Year Ended December 31,
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||||||||||||||
USGS Petroleum Province
1
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|
Acres
|
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Average Royalty Interest
2
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|
Average Percent Leased
3
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|
2017
|
|
2016
|
|
2015
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||||||
Permian Basin
|
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800,654
|
|
|
1.9
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%
|
|
61.6
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%
|
|
39
|
|
|
19
|
|
|
31
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|
Western Gulf (onshore)
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297,303
|
|
|
3.5
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%
|
|
61.2
|
%
|
|
7
|
|
|
14
|
|
|
10
|
|
Louisiana-Mississippi Salt Basins
|
|
238,426
|
|
|
4.1
|
%
|
|
64.9
|
%
|
|
4
|
|
|
1
|
|
|
—
|
|
North-Central Montana
|
|
138,027
|
|
|
3.0
|
%
|
|
11.6
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Marathon Thrust Belt
|
|
117,442
|
|
|
4.9
|
%
|
|
1.6
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Williston Basin
|
|
65,974
|
|
|
2.7
|
%
|
|
38.0
|
%
|
|
108
|
|
|
92
|
|
|
106
|
|
Bend Arch-Fort Worth Basin
|
|
56,703
|
|
|
4.1
|
%
|
|
14.4
|
%
|
|
1
|
|
|
1
|
|
|
—
|
|
East Texas Basin
|
|
55,155
|
|
|
2.6
|
%
|
|
79.9
|
%
|
|
556
|
|
|
179
|
|
|
381
|
|
Powder River Basin
|
|
33,467
|
|
|
6.1
|
%
|
|
7.2
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Palo Duro Basin
|
|
22,791
|
|
|
3.8
|
%
|
|
1.7
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Anadarko Basin
|
|
13,723
|
|
|
3.6
|
%
|
|
94.3
|
%
|
|
32
|
|
|
18
|
|
|
8
|
|
Arkoma Basin
|
|
9,999
|
|
|
2.4
|
%
|
|
85.3
|
%
|
|
9
|
|
|
13
|
|
|
21
|
|
Cambridge Arch-Central Kansas Uplift
|
|
8,903
|
|
|
5.5
|
%
|
|
83.7
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Southwest Montana
|
|
4,367
|
|
|
6.2
|
%
|
|
7.3
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Cherokee Platform
|
|
2,555
|
|
|
4.7
|
%
|
|
31.3
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Nemaha Uplift
|
|
2,334
|
|
|
1.6
|
%
|
|
41.4
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Montana Thrust Belt
|
|
2,242
|
|
|
4.1
|
%
|
|
—
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Sedgwick Basin
|
|
1,850
|
|
|
2.5
|
%
|
|
82.2
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Black Warrior Basin
|
|
1,500
|
|
|
0.3
|
%
|
|
100.0
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Uinta-Piceance Basin
|
|
560
|
|
|
1.0
|
%
|
|
—
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Other
|
|
1,708
|
|
|
5.2
|
%
|
|
29.9
|
%
|
|
169
|
|
|
180
|
|
|
185
|
|
Total
|
|
1,875,683
|
|
|
3.0
|
%
|
|
51.3
|
%
|
|
925
|
|
|
518
|
|
|
742
|
|
1
|
The basins and regions shown in the table are consistent with USGS petroleum-province delineations.
|
2
|
Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in the basin or region. NPRIs may be denominated as a “fractional royalty,” which entitles the owner to the stated fraction of gross production, or a “fraction of royalty,” where the stated fraction is multiplied by the lease royalty. In cases where our land documentation does not specify the form of NPRI, we have assumed a fractional royalty for purposes of the average royalty interests shown above.
|
3
|
The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the basin or region.
|
|
|
As of December 31, 2017
|
|
Average Daily Production (Boe/d) for the Year Ended December 31,
|
|||||||||||
USGS Petroleum Province
1
|
|
Acres
|
|
Average Royalty Interest
2
|
|
2017
|
|
2016
|
|
2015
|
|||||
North-Central Montana
|
|
457,897
|
|
|
2.5
|
%
|
|
2
|
|
|
13
|
|
|
35
|
|
Western Gulf (onshore)
|
|
282,208
|
|
|
2.8
|
%
|
|
246
|
|
|
157
|
|
|
262
|
|
Anadarko Basin
|
|
280,283
|
|
|
3.4
|
%
|
|
188
|
|
|
200
|
|
|
232
|
|
Permian Basin
|
|
185,069
|
|
|
1.0
|
%
|
|
106
|
|
|
64
|
|
|
72
|
|
Uinta-Piceance Basin
|
|
174,701
|
|
|
2.5
|
%
|
|
21
|
|
|
24
|
|
|
37
|
|
Powder River Basin
|
|
120,722
|
|
|
3.8
|
%
|
|
26
|
|
|
45
|
|
|
98
|
|
East Texas Basin
|
|
78,960
|
|
|
6.9
|
%
|
|
97
|
|
|
96
|
|
|
81
|
|
Southwestern Wyoming
|
|
77,529
|
|
|
2.0
|
%
|
|
415
|
|
|
451
|
|
|
529
|
|
Michigan Basin
|
|
56,512
|
|
|
1.0
|
%
|
|
20
|
|
|
18
|
|
|
21
|
|
Denver Basin
|
|
45,608
|
|
|
4.4
|
%
|
|
156
|
|
|
117
|
|
|
83
|
|
Bend Arch-Fort Worth Basin
|
|
43,514
|
|
|
4.7
|
%
|
|
100
|
|
|
108
|
|
|
160
|
|
Paradox Basin
|
|
43,301
|
|
|
1.3
|
%
|
|
1
|
|
|
—
|
|
|
2
|
|
Arkoma Basin
|
|
38,109
|
|
|
3.0
|
%
|
|
20
|
|
|
23
|
|
|
29
|
|
San Juan Basin
|
|
37,644
|
|
|
1.1
|
%
|
|
4
|
|
|
6
|
|
|
3
|
|
Williston Basin
|
|
34,099
|
|
|
2.1
|
%
|
|
62
|
|
|
59
|
|
|
76
|
|
Louisiana-Mississippi Salt Basins
|
|
26,104
|
|
|
3.8
|
%
|
|
405
|
|
|
705
|
|
|
1,185
|
|
Northern Alaska
|
|
24,214
|
|
|
3.5
|
%
|
|
28
|
|
|
28
|
|
|
32
|
|
Wind River Basin
|
|
8,528
|
|
|
1.1
|
%
|
|
34
|
|
|
27
|
|
|
33
|
|
Cambridge Arch-Central Kansas Uplift
|
|
17,469
|
|
|
4.9
|
%
|
|
3
|
|
|
3
|
|
|
5
|
|
Appalachian Basin
|
|
14,861
|
|
|
2.5
|
%
|
|
706
|
|
|
693
|
|
|
—
|
|
Other
|
|
48,173
|
|
|
1.4
|
%
|
|
91
|
|
|
156
|
|
|
911
|
|
Total
|
|
2,095,505
|
|
|
2.8
|
%
|
|
2,731
|
|
|
2,993
|
|
|
3,886
|
|
1
|
The basins and regions shown in the table are consistent with USGS petroleum-province delineations.
|
2
|
Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in the basin or region.
|
|
|
As of December 31, 2017
|
|
Average Daily Production (Boe/d) for the Year Ended December 31,
|
|||||||||||
USGS Petroleum Province
1
|
|
Gross Acres
2
|
|
Net Acres
2
|
|
2017
|
|
2016
|
|
2015
|
|||||
East Texas Basin
|
|
148,121
|
|
|
50,693
|
|
|
9,803
|
|
|
4,776
|
|
|
2,341
|
|
Western Gulf (onshore)
|
|
122,167
|
|
|
18,692
|
|
|
640
|
|
|
1,494
|
|
|
1,234
|
|
Williston Basin
|
|
59,875
|
|
|
7,895
|
|
|
548
|
|
|
1,377
|
|
|
1,425
|
|
Louisiana-Mississippi Salt Basins
|
|
59,117
|
|
|
7,999
|
|
|
476
|
|
|
932
|
|
|
1,007
|
|
Bend Arch-Fort Worth Basin
|
|
52,885
|
|
|
13,475
|
|
|
54
|
|
|
118
|
|
|
108
|
|
Anadarko Basin
|
|
30,939
|
|
|
21,254
|
|
|
687
|
|
|
1,018
|
|
|
1,205
|
|
Southwestern Wyoming
|
|
14,056
|
|
|
2,050
|
|
|
24
|
|
|
11
|
|
|
1
|
|
Michigan Basin
|
|
13,287
|
|
|
1,330
|
|
|
—
|
|
|
6
|
|
|
6
|
|
Powder River Basin
|
|
12,936
|
|
|
3,382
|
|
|
68
|
|
|
103
|
|
|
169
|
|
Arkoma Basin
|
|
9,045
|
|
|
2,333
|
|
|
136
|
|
|
277
|
|
|
341
|
|
Permian Basin
|
|
8,113
|
|
|
5,051
|
|
|
232
|
|
|
323
|
|
|
214
|
|
Denver Basin
|
|
4,923
|
|
|
1,040
|
|
|
133
|
|
|
130
|
|
|
5
|
|
Paradox Basin
|
|
2,602
|
|
|
1,281
|
|
|
2
|
|
|
4
|
|
|
5
|
|
North-Central Montana
|
|
2,080
|
|
|
605
|
|
|
—
|
|
|
1
|
|
|
1
|
|
Uinta-Piceance Basin
|
|
1,005
|
|
|
482
|
|
|
50
|
|
|
68
|
|
|
—
|
|
San Juan Basin
|
|
960
|
|
|
334
|
|
|
—
|
|
|
15
|
|
|
11
|
|
Wind River Basin
|
|
440
|
|
|
43
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Southern Oklahoma
|
|
390
|
|
|
92
|
|
|
97
|
|
|
132
|
|
|
174
|
|
Cherokee Platform
|
|
328
|
|
|
137
|
|
|
—
|
|
|
1
|
|
|
5
|
|
Illinois Basin
|
|
200
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other
|
|
1
|
|
|
—
|
|
|
—
|
|
|
279
|
|
|
128
|
|
Total
|
|
543,470
|
|
|
138,184
|
|
|
12,950
|
|
|
11,065
|
|
|
8,380
|
|
1
|
The basins and regions shown in the table are consistent with USGS petroleum-province delineations.
|
2
|
Excludes acreage that is not quantifiable due to incomplete seller records.
|
Mineral and Royalty Interests
|
|
Working Interests
|
||||||
USGS Petroleum Province
1
|
|
Gross Well Count
2
|
|
USGS Petroleum Province
1
|
|
Gross Well Count
2
|
||
Permian Basin
|
|
23,685
|
|
|
Anadarko Basin
|
|
2,898
|
|
Anadarko Basin
|
|
4,068
|
|
|
Uinta-Piceance Basin
|
|
1,378
|
|
East Texas Basin
|
|
3,992
|
|
|
Permian Basin
|
|
908
|
|
Williston Basin
|
|
3,561
|
|
|
East Texas Basin
|
|
907
|
|
Louisiana-Mississippi Salt Basin
|
|
3,504
|
|
|
Arkoma Basin
|
|
751
|
|
Western Gulf (onshore)
|
|
3,494
|
|
|
Western Gulf (onshore)
|
|
640
|
|
Arkoma Basin
|
|
2,009
|
|
|
Louisiana-Mississippi Salt Basin
|
|
546
|
|
Uinta-Piceance Basin
|
|
1,750
|
|
|
Williston Basin
|
|
542
|
|
Bend Arch-Fort Worth Basin
|
|
1,230
|
|
|
Southern Oklahoma
|
|
389
|
|
Michigan Basin
|
|
924
|
|
|
Bend Arch-Fort Worth Basin
|
|
228
|
|
Appalachian Basin
|
|
846
|
|
|
Appalachian Basin
|
|
189
|
|
Southwestern Wyoming
|
|
783
|
|
|
Nemaha Uplift
|
|
104
|
|
Denver Basin
|
|
707
|
|
|
Powder River Basin
|
|
63
|
|
Cherokee Platform
|
|
642
|
|
|
Michigan Basin
|
|
62
|
|
San Juan Basin
|
|
627
|
|
|
Denver Basin
|
|
21
|
|
North-Central Montana
|
|
605
|
|
|
Cherokee Platform
|
|
16
|
|
Powder River Basin
|
|
490
|
|
|
Palo Duro Basin
|
|
11
|
|
Wyoming Thrust Belt
|
|
391
|
|
|
North-Central Montana
|
|
10
|
|
Southern Oklahoma
|
|
369
|
|
|
Paradox Basin
|
|
8
|
|
San Joaquin Basin
|
|
363
|
|
|
Black Warrior Basin
|
|
5
|
|
Other
|
|
1,688
|
|
|
Other
|
|
12
|
|
Total
|
|
55,728
|
|
|
Total
|
|
9,688
|
|
1
|
The basins and regions shown in the table are consistent with USGS petroleum-province delineations.
|
2
|
We own both mineral and royalty interests and working interests in 3,973 of the wells shown in each column above.
|
|
|
Acreage as of December 31, 2017
1
|
|||||||||||||
|
|
Mineral and Royalty Interests
|
|
Working Interests
|
|||||||||||
Resource Play
2
|
|
Mineral Interests
|
|
NPRIs
|
|
ORRIs
|
|
Gross
|
|
Net
|
|||||
Bakken Shale
|
|
366,359
|
|
|
40,022
|
|
|
15,450
|
|
|
55,220
|
|
|
7,239
|
|
Haynesville Shale
|
|
360,587
|
|
|
7,335
|
|
|
28,741
|
|
|
191,523
|
|
|
55,169
|
|
Three Forks
|
|
355,665
|
|
|
37,203
|
|
|
13,810
|
|
|
55,422
|
|
|
6,866
|
|
Bossier Shale
|
|
329,717
|
|
|
1,896
|
|
|
20,530
|
|
|
178,902
|
|
|
53,753
|
|
Wolfcamp
—
Midland
|
|
288,718
|
|
|
134,284
|
|
|
124,272
|
|
|
160
|
|
|
4
|
|
Marcellus Shale
|
|
246,542
|
|
|
—
|
|
|
13,467
|
|
|
—
|
|
|
—
|
|
Canyon Lime
|
|
226,149
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Tuscaloosa Marine Shale
|
|
189,147
|
|
|
23,397
|
|
|
2,192
|
|
|
—
|
|
|
—
|
|
Wolfcamp
—
Delaware
|
|
137,759
|
|
|
38,021
|
|
|
6,403
|
|
|
2,642
|
|
|
1,291
|
|
Granite Wash
|
|
109,876
|
|
|
5,031
|
|
|
104,308
|
|
|
4,840
|
|
|
1,254
|
|
Fayetteville Shale
|
|
74,401
|
|
|
4,789
|
|
|
11,861
|
|
|
—
|
|
|
—
|
|
Eagle Ford Shale
|
|
67,478
|
|
|
107,019
|
|
|
49,613
|
|
|
1,147
|
|
|
87
|
|
Barnett Shale
|
|
61,788
|
|
|
4,164
|
|
|
37,633
|
|
|
13,417
|
|
|
7,747
|
|
1
|
Excludes acreage for which we have incomplete seller records.
|
2
|
The plays above have been delineated based on information from the Energy Information Administration ("EIA"), the USGS, or state agencies, or according to areas of the most active industry development.
|
|
|
As of December 31, 2017
|
|
Average Daily Production (Boe/d) for the Year Ended December 31,
|
||||||||||||||
Resource Play
1
|
|
Acres
|
|
Average Ownership Interest
2
|
|
Average Ownership Leased
3
|
|
2017
|
|
2016
|
|
2015
|
||||||
Bakken Shale
|
|
366,359
|
|
|
17.2
|
%
|
|
76.6
|
%
|
|
1,877
|
|
|
1,659
|
|
|
1,746
|
|
Haynesville Shale
|
|
360,587
|
|
|
63.7
|
%
|
|
52.2
|
%
|
|
5,391
|
|
|
3,727
|
|
|
2,728
|
|
Three Forks
|
|
355,665
|
|
|
16.8
|
%
|
|
78.5
|
%
|
|
991
|
|
|
968
|
|
|
823
|
|
Bossier Shale
|
|
329,717
|
|
|
68.1
|
%
|
|
49.1
|
%
|
|
337
|
|
|
330
|
|
|
351
|
|
Wolfcamp
—
Midland
|
|
288,718
|
|
|
4.6
|
%
|
|
98.1
|
%
|
|
659
|
|
|
136
|
|
|
76
|
|
Marcellus Shale
|
|
246,542
|
|
|
14.4
|
%
|
|
26.9
|
%
|
|
118
|
|
|
111
|
|
|
71
|
|
Canyon Lime
|
|
226,149
|
|
|
30.5
|
%
|
|
30.2
|
%
|
|
67
|
|
|
16
|
|
|
8
|
|
Tuscaloosa Marine Shale
|
|
189,147
|
|
|
58.1
|
%
|
|
43.8
|
%
|
|
35
|
|
|
52
|
|
|
46
|
|
Wolfcamp
—
Delaware
|
|
137,759
|
|
|
9.7
|
%
|
|
97.0
|
%
|
|
785
|
|
|
437
|
|
|
148
|
|
Granite Wash
|
|
109,876
|
|
|
15.0
|
%
|
|
60.6
|
%
|
|
136
|
|
|
167
|
|
|
194
|
|
Fayetteville Shale
|
|
74,401
|
|
|
56.0
|
%
|
|
78.6
|
%
|
|
1,014
|
|
|
1,181
|
|
|
1,349
|
|
Eagle Ford Shale
|
|
67,478
|
|
|
14.1
|
%
|
|
85.4
|
%
|
|
1,743
|
|
|
2,095
|
|
|
2,355
|
|
Barnett Shale
|
|
61,788
|
|
|
15.8
|
%
|
|
57.2
|
%
|
|
172
|
|
|
181
|
|
|
239
|
|
1
|
The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industry development.
|
2
|
Ownership interest is equal to the percentage that our undivided ownership interest in a tract bears to the entire tract. The per-play average ownership interests shown above reflect the weighted average of our ownership interests in all tracts in the play. Our weighted-average mineral royalty for all of our mineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average royalty interest in our mineral and royalty interests.
|
3
|
The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the play.
|
|
|
As of December 31, 2017
|
|
Average Daily Production (Boe/d) for the Year Ended December 31,
|
||||||||||||||
Resource Play
1
|
|
Acres
|
|
Average Royalty Interest
2
|
|
Average Percent Leased
3
|
|
2017
|
|
2016
|
|
2015
|
||||||
Wolfcamp
—
Midland
|
|
134,284
|
|
|
0.7
|
%
|
|
82.8
|
%
|
|
25
|
|
|
11
|
|
|
22
|
|
Eagle Ford Shale
|
|
107,019
|
|
|
1.2
|
%
|
|
42.4
|
%
|
|
6
|
|
|
14
|
|
|
3
|
|
Bakken Shale
|
|
40,022
|
|
|
1.3
|
%
|
|
57.7
|
%
|
|
74
|
|
|
63
|
|
|
56
|
|
Wolfcamp
—
Delaware
|
|
38,021
|
|
|
0.6
|
%
|
|
86.7
|
%
|
|
7
|
|
|
4
|
|
|
1
|
|
Three Forks
|
|
37,203
|
|
|
1.2
|
%
|
|
61.3
|
%
|
|
37
|
|
|
36
|
|
|
50
|
|
Tuscaloosa Marine Shale
|
|
23,397
|
|
|
0.5
|
%
|
|
93.3
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Haynesville Shale
|
|
7,335
|
|
|
4.2
|
%
|
|
96.1
|
%
|
|
443
|
|
|
167
|
|
|
325
|
|
Granite Wash
|
|
5,031
|
|
|
0.8
|
%
|
|
100.0
|
%
|
|
31
|
|
|
16
|
|
|
5
|
|
Fayetteville Shale
|
|
4,789
|
|
|
0.1
|
%
|
|
100.0
|
%
|
|
9
|
|
|
13
|
|
|
—
|
|
Barnett Shale
|
|
4,164
|
|
|
2.7
|
%
|
|
86.9
|
%
|
|
1
|
|
|
1
|
|
|
—
|
|
Bossier Shale
|
|
1,896
|
|
|
2.9
|
%
|
|
51.8
|
%
|
|
113
|
|
|
11
|
|
|
53
|
|
Canyon Lime
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Marcellus Shale
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
1
|
The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industry development.
|
2
|
Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis for the given area. NPRIs may be denominated as a “fractional royalty,” which entitles the owner to the stated fraction of gross production, or a “fraction of royalty,” where the stated fraction is multiplied by the lease royalty. In cases where our land documentation does not specify the form of NPRI, we have assumed a fractional royalty for purposes of the average royalty interests shown above.
|
3
|
The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the play.
|
|
|
As of December 31, 2017
|
|
Average Daily Production (Boe/d) for the Year Ended December 31,
|
|||||||||||
Resource Play
1
|
|
Acres
|
|
Average Royalty Interest
2
|
|
2017
|
|
2016
|
|
2015
|
|||||
Wolfcamp
—
Midland
|
|
124,272
|
|
|
0.4
|
%
|
|
31
|
|
|
<1
|
|
|
5
|
|
Granite Wash
|
|
104,308
|
|
|
1.6
|
%
|
|
72
|
|
|
155
|
|
|
115
|
|
Eagle Ford Shale
|
|
49,613
|
|
|
2.2
|
%
|
|
193
|
|
|
95
|
|
|
204
|
|
Barnett Shale
|
|
37,633
|
|
|
5.0
|
%
|
|
99
|
|
|
109
|
|
|
158
|
|
Haynesville Shale
|
|
28,741
|
|
|
4.9
|
%
|
|
383
|
|
|
686
|
|
|
1,111
|
|
Bossier Shale
|
|
20,530
|
|
|
5.7
|
%
|
|
8
|
|
|
28
|
|
|
57
|
|
Bakken Shale
|
|
15,450
|
|
|
1.3
|
%
|
|
32
|
|
|
34
|
|
|
41
|
|
Three Forks
|
|
13,810
|
|
|
1.3
|
%
|
|
25
|
|
|
21
|
|
|
27
|
|
Marcellus Shale
|
|
13,467
|
|
|
2.3
|
%
|
|
19
|
|
|
37
|
|
|
6
|
|
Fayetteville Shale
|
|
11,861
|
|
|
4.0
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Wolfcamp
—
Delaware
|
|
6,403
|
|
|
2.1
|
%
|
|
4
|
|
|
—
|
|
|
—
|
|
Tuscaloosa Marine Shale
|
|
2,192
|
|
|
13.5
|
%
|
|
—
|
|
|
<1
|
|
|
—
|
|
Canyon Lime
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
1
|
The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industry development.
|
2
|
Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in this play.
|
|
|
As of December 31, 2017
|
|
Average Daily Production (Boe/d) for the Year Ended December 31,
|
|||||||||||
Resource Play
1
|
|
Gross Acres
2
|
|
Net Acres
2
|
|
2017
|
|
2016
|
|
2015
|
|||||
Haynesville Shale
|
|
191,523
|
|
|
55,169
|
|
|
9,631
|
|
|
5,077
|
|
|
2,909
|
|
Bossier Shale
|
|
178,902
|
|
|
53,753
|
|
|
690
|
|
|
309
|
|
|
135
|
|
Three Forks
|
|
55,422
|
|
|
6,866
|
|
|
194
|
|
|
491
|
|
|
551
|
|
Bakken Shale
|
|
55,220
|
|
|
7,239
|
|
|
347
|
|
|
864
|
|
|
792
|
|
Barnett Shale
|
|
13,417
|
|
|
7,747
|
|
|
51
|
|
|
87
|
|
|
104
|
|
Granite Wash
|
|
4,840
|
|
|
1,254
|
|
|
283
|
|
|
429
|
|
|
537
|
|
Wolfcamp
—
Delaware
|
|
2,642
|
|
|
1,291
|
|
|
143
|
|
|
150
|
|
|
23
|
|
Eagle Ford Shale
|
|
1,147
|
|
|
87
|
|
|
—
|
|
|
76
|
|
|
11
|
|
Wolfcamp
—
Midland
|
|
160
|
|
|
4
|
|
|
2
|
|
|
1
|
|
|
—
|
|
Canyon Lime
|
|
—
|
|
|
—
|
|
|
14
|
|
|
—
|
|
|
—
|
|
Fayetteville Shale
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23
|
|
|
—
|
|
Marcellus Shale
|
|
—
|
|
|
—
|
|
|
—
|
|
|
<1
|
|
|
—
|
|
Tuscaloosa Marine Shale
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
1
|
The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industry development.
|
2
|
Excludes acreage that is not quantifiable due to incomplete seller records.
|
•
|
Comparison of historical operating expenses from the lease operating statements to the operating costs input in the reserves database;
|
•
|
Review of working interests and net revenue interests in the reserves database against our well ownership system;
|
•
|
Review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database;
|
•
|
Evaluation of capital cost assumptions derived from Authority for Expenditure estimates received;
|
•
|
Review of actual historical production volumes compared to projections in the reserve report;
|
•
|
Discussion of material reserve variances among our internal reservoir engineers and our Senior Vice President, Engineering and Geology; and
|
•
|
Review of preliminary reserve estimates by our President and Chief Executive Officer with our internal technical staff.
|
|
As of December 31,
|
|||||||
|
2017
1
|
|
2016
2
|
|
2015
3
|
|||
|
(Unaudited)
|
|||||||
Estimated proved developed reserves
4
:
|
|
|
|
|
|
|||
Oil (MBbls)
|
17,891
|
|
|
18,150
|
|
|
15,497
|
|
Natural gas (MMcf)
|
233,017
|
|
|
223,057
|
|
|
174,555
|
|
Total (MBoe)
|
56,727
|
|
|
55,327
|
|
|
44,590
|
|
Estimated proved undeveloped reserves
5
:
|
|
|
|
|
|
|||
Oil (MBbls)
|
8
|
|
|
218
|
|
|
345
|
|
Natural gas (MMcf)
|
67,257
|
|
|
47,282
|
|
|
29,120
|
|
Total (MBoe)
|
11,218
|
|
|
8,098
|
|
|
5,198
|
|
Estimated proved reserves:
|
|
|
|
|
|
|||
Oil (MBbls)
|
17,899
|
|
|
18,368
|
|
|
15,842
|
|
Natural gas (MMcf)
|
300,274
|
|
|
270,339
|
|
|
203,675
|
|
Total (MBoe)
|
67,945
|
|
|
63,425
|
|
|
49,788
|
|
Percent proved developed
|
83.5
|
%
|
|
87.2
|
%
|
|
89.6
|
%
|
1
|
Estimates of reserves as of
December 31, 2017
, were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period from January through December 2017. For oil volumes, the average WTI spot oil price of $51.34 per barrel is used for estimates of reserves for all the properties as of
December 31, 2017
. This average price is adjusted for quality, transportation fees, and market differentials. For natural gas volumes, the average Henry Hub price of $2.98 per MMBTU is used for estimates of reserves for all the properties as of
December 31, 2017
. This average price is adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates exclude NGL quantities. When taking these adjustments into account, the average adjusted prices weighted by production over the remaining lives of the properties are $46.59 per barrel for oil and $2.70 per Mcf for natural gas as of
December 31, 2017
.
|
2
|
Estimates of reserves as of December 31, 2016 were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period January through December 2016. For oil volumes, the average WTI spot oil price of $42.75 per barrel is used for estimates of reserves for all the properties as of December 31, 2016. These average prices are adjusted for quality, transportation fees, and market differentials. For natural gas volumes, the average Henry Hub price of $2.48 per MMBTU is used for estimates of reserves for all the properties as of December 31, 2016. These average prices are adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates exclude NGL quantities. When taking these adjustments into account, the average adjusted prices weighted by production over the remaining lives of the properties are $37.50 per barrel for oil and $2.14 per Mcf for natural gas.
|
3
|
Estimates of reserves as of December 31, 2015 were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period January through December 2015. For oil volumes, the average WTI spot oil price of $50.28 per barrel is used for estimates of reserves for all the properties as of December 31, 2015. These average prices are adjusted for quality, transportation fees, and market differentials. For natural gas volumes, the average Henry Hub price of $2.59 per MMBTU is used for estimates of reserves for all the properties as of December 31, 2015. These average prices are adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates exclude NGL quantities. When taking these adjustments into account, the average adjusted gas price weighted by production over the remaining lives of the properties is $2.45 per Mcf.
|
4
|
Proved developed reserves of 61, 74, and 84 MBoe as of
December 31, 2017
, 2016, and 2015, respectively, were attributable to noncontrolling interests in our consolidated subsidiaries.
|
5
|
As of
December 31, 2017
, 2016, and 2015, no proved undeveloped reserves were attributable to noncontrolling interests in our consolidated subsidiaries.
|
|
Estimated Proved Undeveloped Reserves
|
|
|
(Unaudited)
|
|
As of December 31, 2016
|
8,098
|
|
Acquisitions of reserves
|
920
|
|
Divestiture of reserves
|
(672
|
)
|
Extensions and discoveries
|
4,564
|
|
Revisions of previous estimates
|
945
|
|
Transfers to estimated proved developed
|
(2,637
|
)
|
As of December 31, 2017
|
11,218
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Production:
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate (MBbls)
1
|
|
3,552
|
|
|
3,680
|
|
|
3,565
|
|
|||
Natural gas (MMcf)
1
|
|
59,779
|
|
|
47,498
|
|
|
41,389
|
|
|||
Total (MBoe)
|
|
13,515
|
|
|
11,596
|
|
|
10,463
|
|
|||
Average daily production (MBoe/d)
|
|
37.0
|
|
|
31.7
|
|
|
28.7
|
|
|||
Realized Prices
2
:
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate (per Bbl)
|
|
$
|
47.78
|
|
|
$
|
38.69
|
|
|
$
|
45.87
|
|
Natural gas and natural gas liquids (per Mcf)
1
|
|
$
|
3.19
|
|
|
$
|
2.59
|
|
|
$
|
2.80
|
|
Unit Cost per Boe:
|
|
|
|
|
|
|
|
|
|
|||
Production costs and ad valorem taxes
|
|
$
|
3.51
|
|
|
$
|
3.06
|
|
|
$
|
3.42
|
|
1
|
As a mineral-and-royalty interest owner, we are often provided insufficient and inconsistent data by our operators related to NGLs. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. As such, the realized prices for natural gas account for all value attributable to NGLs. The oil and condensate production volumes and natural gas production volumes do not include NGL volumes.
|
2
|
Excludes the effect of commodity derivative instruments.
|
State
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
|||
Texas
|
|
342,912
|
|
|
4,717,981
|
|
|
5,060,893
|
|
Oklahoma
|
|
116,555
|
|
|
458,278
|
|
|
574,833
|
|
Louisiana
|
|
35,259
|
|
|
498,331
|
|
|
533,590
|
|
Montana
|
|
20,844
|
|
|
545,925
|
|
|
566,769
|
|
North Dakota
|
|
18,016
|
|
|
1,141,046
|
|
|
1,159,062
|
|
Arkansas
|
|
4,887
|
|
|
1,274,169
|
|
|
1,279,056
|
|
Mississippi
|
|
4,576
|
|
|
2,403,176
|
|
|
2,407,752
|
|
Alabama
|
|
2,859
|
|
|
2,057,740
|
|
|
2,060,599
|
|
Nevada
|
|
—
|
|
|
792,588
|
|
|
792,588
|
|
Florida
|
|
—
|
|
|
743,452
|
|
|
743,452
|
|
Other
|
|
82,555
|
|
|
1,532,785
|
|
|
1,615,340
|
|
Total
|
|
628,463
|
|
|
16,165,471
|
|
|
16,793,934
|
|
State
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
|||
Texas
|
|
203,805
|
|
|
1,104,471
|
|
|
1,308,276
|
|
Oklahoma
|
|
6,976
|
|
|
5,829
|
|
|
12,805
|
|
Louisiana
|
|
10,508
|
|
|
86,521
|
|
|
97,029
|
|
Montana
|
|
11,684
|
|
|
172,876
|
|
|
184,560
|
|
North Dakota
|
|
20,100
|
|
|
20,898
|
|
|
40,998
|
|
Arkansas
|
|
3,974
|
|
|
30,122
|
|
|
34,096
|
|
Mississippi
|
|
10,533
|
|
|
137,299
|
|
|
147,832
|
|
Wyoming
|
|
1,360
|
|
|
17,160
|
|
|
18,520
|
|
New Mexico
|
|
14,289
|
|
|
960
|
|
|
15,249
|
|
Kansas
|
|
9,042
|
|
|
2,983
|
|
|
12,025
|
|
Other
|
|
367
|
|
|
3,926
|
|
|
4,293
|
|
Total
|
|
292,638
|
|
|
1,583,045
|
|
|
1,875,683
|
|
State
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
|||
Texas
|
|
289,062
|
|
|
243,733
|
|
|
532,795
|
|
Oklahoma
|
|
142,300
|
|
|
94,240
|
|
|
236,540
|
|
Louisiana
|
|
15,907
|
|
|
93,997
|
|
|
109,904
|
|
Montana
|
|
295,401
|
|
|
183,588
|
|
|
478,989
|
|
Wyoming
|
|
133,461
|
|
|
100,516
|
|
|
233,977
|
|
New Mexico
|
|
46,151
|
|
|
19,240
|
|
|
65,391
|
|
Utah
|
|
40,510
|
|
|
153,317
|
|
|
193,827
|
|
Michigan
|
|
55,272
|
|
|
1,239
|
|
|
56,511
|
|
Colorado
|
|
27,108
|
|
|
23,647
|
|
|
50,755
|
|
Alaska
|
|
7,664
|
|
|
16,550
|
|
|
24,214
|
|
Other
|
|
75,808
|
|
|
36,794
|
|
|
112,602
|
|
Total
|
|
1,128,644
|
|
|
966,861
|
|
|
2,095,505
|
|
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
||||||||||||
State
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Texas
|
|
206,581
|
|
|
55,208
|
|
|
140,227
|
|
|
43,234
|
|
|
346,808
|
|
|
98,442
|
|
Louisiana
|
|
41,683
|
|
|
4,638
|
|
|
14,662
|
|
|
2,812
|
|
|
56,345
|
|
|
7,450
|
|
North Dakota
|
|
48,510
|
|
|
6,505
|
|
|
7,565
|
|
|
793
|
|
|
56,075
|
|
|
7,298
|
|
Wyoming
|
|
22,210
|
|
|
4,161
|
|
|
4,902
|
|
|
994
|
|
|
27,112
|
|
|
5,155
|
|
Michigan
|
|
13,208
|
|
|
1,330
|
|
|
79
|
|
|
—
|
|
|
13,287
|
|
|
1,330
|
|
Oklahoma
|
|
11,623
|
|
|
3,030
|
|
|
10
|
|
|
3
|
|
|
11,633
|
|
|
3,033
|
|
Colorado
|
|
7,725
|
|
|
2,601
|
|
|
—
|
|
|
—
|
|
|
7,725
|
|
|
2,601
|
|
Kansas
|
|
6,480
|
|
|
6,213
|
|
|
921
|
|
|
—
|
|
|
7,401
|
|
|
6,213
|
|
New Mexico
|
|
6,238
|
|
|
3,622
|
|
|
160
|
|
|
80
|
|
|
6,398
|
|
|
3,702
|
|
South Dakota
|
|
2,160
|
|
|
504
|
|
|
880
|
|
|
55
|
|
|
3,040
|
|
|
559
|
|
Other
|
|
6,436
|
|
|
2,127
|
|
|
1,210
|
|
|
274
|
|
|
7,646
|
|
|
2,401
|
|
Total
|
|
372,854
|
|
|
89,939
|
|
|
170,616
|
|
|
48,245
|
|
|
543,470
|
|
|
138,184
|
|
|
|
2018 Expirations
|
|
2019 Expirations
|
|
2020 Expirations
|
|||||||||||||
Net Undeveloped
Acreage
|
|
Net Acreage
without Ext. Opt.
|
|
Net Acreage
with Ext. Opt.
|
|
Net Acreage
without Ext. Opt.
|
|
Net Acreage
with Ext. Opt.
|
|
Net Acreage
without Ext. Opt.
|
|
Net Acreage
with Ext. Opt.
|
|||||||
48,245
|
|
|
13,828
|
|
|
9
|
|
|
2,328
|
|
|
300
|
|
|
1,355
|
|
|
582
|
|
|
|
Year Ended December 31,
|
|||||||
|
|
2017
|
|
2016
|
|
2015
|
|||
Gross development wells:
|
|
|
|
|
|
|
|
|
|
Productive
|
|
23.0
|
|
|
47.0
|
|
|
74.0
|
|
Dry
|
|
—
|
|
|
—
|
|
|
1.0
|
|
Total
|
|
23.0
|
|
|
47.0
|
|
|
75.0
|
|
Net development wells:
|
|
|
|
|
|
|
|
|
|
Productive
|
|
6.1
|
|
|
4.7
|
|
|
2.9
|
|
Dry
|
|
—
|
|
|
—
|
|
|
<0.1
|
|
Total
|
|
6.1
|
|
|
4.7
|
|
|
2.9
|
|
|
|
Year Ended December 31,
|
||||
|
|
2017
|
|
2016
|
|
2015
|
Exxon Mobil Corporation
|
|
20.8%
|
|
11.0%
|
|
*
|
*
|
Accounted for less than 10% of total revenues for the period indicated.
|
•
|
the domestic and foreign supply of and demand for oil and natural gas;
|
•
|
market expectations about future prices of oil and natural gas;
|
•
|
the level of global oil and natural gas exploration and production;
|
•
|
the cost of exploring for, developing, producing, and delivering oil and natural gas;
|
•
|
the price and quantity of foreign imports;
|
•
|
political and economic conditions in oil producing regions, including the Middle East, Africa, South America, and Russia;
|
•
|
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
|
•
|
trading in oil and natural gas derivative contracts;
|
•
|
the level of consumer product demand;
|
•
|
weather conditions and natural disasters;
|
•
|
technological advances affecting energy consumption;
|
•
|
domestic and foreign governmental regulations and taxes;
|
•
|
the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;
|
•
|
the proximity, cost, availability, and capacity of oil and natural gas pipelines and other transportation facilities;
|
•
|
the price and availability of alternative fuels; and
|
•
|
overall domestic and global economic conditions.
|
|
|
Year Ended December 31, 2017
|
|
During the Five Years Prior to 2018
|
|
As of December 31,
|
||||||||||||||||||||||
|
|
High
|
|
Low
|
|
High
1
|
|
Low
2
|
|
2017
|
|
2016
|
|
2015
|
||||||||||||||
WTI Light sweet crude oil ($/Bbl)
|
|
$
|
60.46
|
|
|
$
|
42.48
|
|
|
$
|
110.62
|
|
|
$
|
26.19
|
|
|
$
|
60.46
|
|
|
$
|
53.75
|
|
|
$
|
37.13
|
|
Henry Hub spot market price of natural gas ($/MMBtu)
|
|
$
|
3.71
|
|
|
$
|
2.44
|
|
|
$
|
8.15
|
|
|
$
|
1.49
|
|
|
$
|
3.69
|
|
|
$
|
3.71
|
|
|
$
|
2.28
|
|
1
|
High prices for WTI and Henry Hub were in 2013 and 2014, respectively
|
2
|
Low prices for WTI and Henry Hub were in 2016
|
•
|
recoverable reserves;
|
•
|
future oil and natural gas prices and their applicable differentials;
|
•
|
development plans;
|
•
|
operating costs; and
|
•
|
potential environmental and other liabilities.
|
•
|
the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, operating expenses, and costs;
|
•
|
a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;
|
•
|
a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
|
•
|
the assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which any indemnity we receive is inadequate;
|
•
|
mistaken assumptions about the overall cost of equity or debt;
|
•
|
our ability to obtain satisfactory title to the assets we acquire;
|
•
|
an inability to hire, train, or retain qualified personnel to manage and operate our growing business and assets; and
|
•
|
the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation, or restructuring charges.
|
•
|
the capital costs required for drilling activities by our operators, which could be significantly more than anticipated;
|
•
|
the ability of our operators to access capital;
|
•
|
prevailing commodity prices;
|
•
|
the availability of suitable drilling equipment, production and transportation infrastructure, and qualified operating personnel;
|
•
|
the operators’ expertise, operating efficiency, and financial resources;
|
•
|
approval of other participants in drilling wells;
|
•
|
the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;
|
•
|
the selection of technology;
|
•
|
the selection of counterparties for the marketing and sale of production; and
|
•
|
the rate of production of the reserves.
|
•
|
provisions related to the unitization or pooling of the oil and natural gas properties;
|
•
|
the establishment of maximum rates of production from wells;
|
•
|
the spacing of wells;
|
•
|
the plugging and abandonment of wells; and
|
•
|
the removal of related production equipment.
|
•
|
incur indebtedness;
|
•
|
grant liens;
|
•
|
make certain acquisitions and investments;
|
•
|
enter into hedging arrangements;
|
•
|
enter into transactions with our affiliates;
|
•
|
make distributions to our unitholders; or
|
•
|
enter into a merger, consolidation, or sale of assets.
|
•
|
amount and timing of asset purchases and sales;
|
•
|
cash expenditures;
|
•
|
borrowings;
|
•
|
entry into and repayment of current and future indebtedness;
|
•
|
issuance of additional units; and
|
•
|
the creation, reduction, or increase of reserves in any quarter.
|
•
|
enabling holders of subordinated units to receive distributions; or
|
•
|
hastening the expiration of the subordination period.
|
•
|
the proportionate ownership interest of common and subordinated unitholders in us immediately prior to the issuance will decrease;
|
•
|
the amount of cash distributions on each common and subordinated unit may decrease;
|
•
|
the ratio of our taxable income to distributions may increase;
|
•
|
the relative voting strength of each previously outstanding common and subordinated unit may be diminished; and
|
•
|
the market price of the common units may decline.
|
|
|
Price Range of Common Units
|
|
Distributions
1
|
||||||||||||
|
|
High
|
|
Low
|
|
Per Common Unit
|
|
Per Subordinated Unit
|
||||||||
2016
|
|
|
|
|
|
|
|
|
||||||||
First Quarter
|
|
$
|
15.76
|
|
|
$
|
10.71
|
|
|
$
|
0.2625
|
|
|
$
|
0.18375
|
|
Second Quarter
|
|
$
|
17.15
|
|
|
$
|
13.61
|
|
|
$
|
0.2875
|
|
|
$
|
0.18375
|
|
Third Quarter
|
|
$
|
19.65
|
|
|
$
|
14.71
|
|
|
$
|
0.2875
|
|
|
$
|
0.18375
|
|
Fourth Quarter
|
|
$
|
19.86
|
|
|
$
|
16.94
|
|
|
$
|
0.2875
|
|
|
$
|
0.18375
|
|
|
|
|
|
|
|
|
|
|
||||||||
2017
|
|
|
|
|
|
|
|
|
||||||||
First Quarter
|
|
$
|
19.55
|
|
|
$
|
15.58
|
|
|
$
|
0.2875
|
|
|
$
|
0.18375
|
|
Second Quarter
|
|
$
|
17.21
|
|
|
$
|
15.12
|
|
|
$
|
0.3125
|
|
|
$
|
0.20875
|
|
Third Quarter
|
|
$
|
17.92
|
|
|
$
|
15.52
|
|
|
$
|
0.3125
|
|
|
$
|
0.20875
|
|
Fourth Quarter
|
|
$
|
18.57
|
|
|
$
|
16.71
|
|
|
$
|
0.3125
|
|
|
$
|
0.20875
|
|
1
|
Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a quarter are paid in the following quarter.
|
|
|
As of April 30, 2015
|
|
As of December 31,
|
||||||||||||
|
|
|
2015
|
|
2016
|
|
2017
|
|||||||||
Black Stone Minerals, L.P.
|
|
$
|
100.00
|
|
|
$
|
78.22
|
|
|
$
|
109.07
|
|
|
$
|
110.89
|
|
S&P 500 Index
|
|
100.00
|
|
|
99.47
|
|
|
111.37
|
|
|
135.69
|
|
||||
Alerian MLP Index
|
|
100.00
|
|
|
66.99
|
|
|
79.25
|
|
|
74.08
|
|
Purchases of Common Units
|
||||||||||||||
Period
|
|
Total Number of Common Units Purchased
|
|
Average Price Paid Per Unit
|
|
Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs
|
|
Maximum Dollar Value of Common Units That May Yet Be Purchased Under the Plans or Programs
|
||||||
December 1 – December 31, 2017
|
|
18,999
1
|
|
|
$
|
17.93
|
|
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
||||||
Purchases of Subordinated Units
|
||||||||||||||
Period
|
|
Total Number of Subordinated Units Purchased
|
|
Average Price Paid Per Unit
|
|
Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs
|
|
Maximum Dollar Value of Common Units That May Yet Be Purchased Under the Plans or Programs
|
||||||
December 1 – December 31, 2017
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
1
|
Includes units withheld to satisfy tax withholding obligations upon the vesting of certain restricted common units held by our executive officers and certain other employees.
|
•
|
first
, to the holders of the Series B cumulative convertible preferred units in an amount equal to 7% per annum, subject to certain adjustments;
|
•
|
second
, to the holders of common units, until each common unit has received the applicable minimum quarterly distribution in the amounts specified below plus any arrearages from prior quarters; and
|
•
|
third
, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution.
|
|
|
Minimum Quarterly Distribution (per unit)
|
||
Four Quarters Ending March 31,
|
|
Per Quarter
|
|
Annualized
|
2018
|
|
0.3125
|
|
1.25
|
2019 and thereafter
|
|
0.3375
|
|
1.35
|
•
|
Our common and subordinated unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis, and if distributions are paid, common and subordinated unitholders will receive distributions only to the extent the distribution amount exceeds distributions that are required to be paid to our Series B cumulative convertible preferred unitholders.
|
•
|
Our credit facility restricts our distributions if there is a default under our credit facility or if our borrowing base is lower than the outstanding loans under our credit facility. Among other covenants, our credit facility requires we maintain a ratio of total debt to EBITDAX of 3.50:1.00 or less and a current ratio of 1.00:1.00 or greater. If we are unable to comply with these financial covenants or if we breach any other covenant under our credit facility or any future debt agreements, we could be prohibited from making distributions notwithstanding our stated distribution policy.
|
•
|
Our general partner has the authority to establish cash reserves for the prudent conduct of our business, and the establishment of, or increase in, those reserves could result in a reduction in cash distributions to our unitholders. Our partnership agreement does not limit the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner will be binding on our unitholders.
|
•
|
Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.
|
•
|
We may lack sufficient cash to pay distributions to our unitholders due to shortfalls in cash generated from operations attributable to a number of operational, commercial, or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, working-capital requirements, and anticipated cash needs.
|
|
|
At December 31,
|
||||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
|
|
(in thousands, except per unit amounts)
|
||||||||||||||||||
Total revenue
|
|
$
|
429,659
|
|
|
$
|
260,833
|
|
|
$
|
392,924
|
|
|
$
|
548,321
|
|
|
$
|
463,559
|
|
Net income (loss)
|
|
157,153
|
|
|
20,188
|
|
|
(101,305
|
)
|
|
169,187
|
|
|
168,963
|
|
|||||
Net income (loss) attributable to the general partner and common units and subordinated units subsequent to initial public offering
|
|
152,145
|
|
|
14,437
|
|
|
(108,017
|
)
|
|
*
|
|
*
|
|||||||
Net income (loss) attributable to limited partners per common and subordinated unit (basic)
1
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Per common unit (basic)
|
|
1.01
|
|
|
0.26
|
|
|
(0.56
|
)
|
|
*
|
|
*
|
|||||||
Per subordinated unit (basic)
|
|
0.56
|
|
|
(0.11
|
)
|
|
(0.56
|
)
|
|
*
|
|
*
|
|||||||
Net income (loss) attributable to limited partners per common and subordinated unit (diluted)
1
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Per common unit (diluted)
|
|
1.01
|
|
|
0.26
|
|
|
(0.56
|
)
|
|
*
|
|
*
|
|||||||
Per subordinated unit (diluted)
|
|
0.56
|
|
|
(0.11
|
)
|
|
(0.56
|
)
|
|
*
|
|
*
|
|||||||
Cash distributions declared per common and subordinated unit
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Per common unit
|
|
1.20
|
|
|
1.10
|
|
|
0.42
|
|
|
*
|
|
*
|
|||||||
Per subordinated unit
|
|
0.79
|
|
|
0.74
|
|
|
0.42
|
|
|
*
|
|
*
|
|||||||
Total assets
2
|
|
1,576,451
|
|
|
1,128,827
|
|
|
1,061,436
|
|
|
1,326,782
|
|
|
1,444,413
|
|
|||||
Long-term debt
|
|
388,000
|
|
|
316,000
|
|
|
66,000
|
|
|
394,000
|
|
|
451,000
|
|
|||||
Total mezzanine equity
|
|
322,422
|
|
|
54,015
|
|
|
79,162
|
|
|
161,165
|
|
|
161,392
|
|
*
|
Information is not applicable for the periods prior to our IPO.
|
1
|
See Note 13 – Earnings Per Unit in the consolidated financial statements included elsewhere in this Annual Report.
|
2
|
We recorded noncash impairments of oil and natural gas properties in the amounts of
$6.8 million
,
$249.6 million
,
$117.9 million
, and
$57.1 million
, for the years ended December 31, 2016, 2015, 2014, and 2013, respectively. We did not have impairments of oil and natural gas properties for the year ended December 31, 2017.
|
|
|
2017
|
||||||||||||||
Benchmark Prices
|
|
Fourth Quarter
|
|
Third Quarter
|
|
Second Quarter
|
|
First Quarter
|
||||||||
WTI spot oil ($/Bbl)
1
|
|
$
|
60.46
|
|
|
$
|
48.18
|
|
|
$
|
46.02
|
|
|
$
|
50.54
|
|
Henry Hub spot natural gas ($/MMBtu)
1
|
|
$
|
3.69
|
|
|
$
|
2.95
|
|
|
$
|
2.98
|
|
|
$
|
3.13
|
|
1
|
Source: EIA
|
|
|
2017
|
||||||||||
U.S. Rotary Rig Count
1
|
|
Fourth Quarter
|
|
Third Quarter
|
|
Second Quarter
|
|
First Quarter
|
||||
Oil
|
|
747
|
|
|
750
|
|
|
756
|
|
|
662
|
|
Natural gas
|
|
182
|
|
|
189
|
|
|
184
|
|
|
160
|
|
Other
|
|
—
|
|
|
1
|
|
|
—
|
|
|
2
|
|
Total
|
|
929
|
|
|
940
|
|
|
940
|
|
|
824
|
|
1
|
Source: Baker Hughes Incorporated
|
|
|
2017
|
||||||||||
Region
1
|
|
Fourth Quarter
|
|
Third Quarter
|
|
Second Quarter
|
|
First Quarter
|
||||
|
|
(Bcf)
|
||||||||||
East
|
|
740
|
|
|
861
|
|
|
564
|
|
|
268
|
|
Midwest
|
|
875
|
|
|
989
|
|
|
699
|
|
|
479
|
|
Mountain
|
|
183
|
|
|
220
|
|
|
187
|
|
|
142
|
|
Pacific
|
|
268
|
|
|
311
|
|
|
287
|
|
|
216
|
|
South Central
|
|
1,060
|
|
|
1,127
|
|
|
1,151
|
|
|
946
|
|
Total
|
|
3,126
|
|
|
3,508
|
|
|
2,888
|
|
|
2,051
|
|
1
|
Source: EIA
|
•
|
volumes of oil and natural gas produced;
|
•
|
commodity prices including the effect of hedges; and
|
•
|
Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures.
|
•
|
Oil
. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.
|
•
|
Natural Gas.
The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(in thousands)
|
||||||||||
Net income (loss)
|
|
$
|
157,153
|
|
|
$
|
20,188
|
|
|
$
|
(101,305
|
)
|
Adjustments to reconcile to Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
||||
Depreciation, depletion and amortization
|
|
114,534
|
|
|
102,487
|
|
|
104,298
|
|
|||
Interest expense
|
|
15,694
|
|
|
7,547
|
|
|
6,418
|
|
|||
Impairment of oil and natural gas properties
|
|
—
|
|
|
6,775
|
|
|
249,569
|
|
|||
Accretion of asset retirement obligations
|
|
1,026
|
|
|
892
|
|
|
1,075
|
|
|||
Equity-based compensation
1
|
|
33,045
|
|
|
43,138
|
|
|
18,000
|
|
|||
Unrealized (gain) loss on commodity derivative instruments
|
|
(11,691
|
)
|
|
81,253
|
|
|
(27,063
|
)
|
|||
Adjusted EBITDA
|
|
309,761
|
|
|
262,280
|
|
|
250,992
|
|
|||
Adjustments to distributable cash flow:
|
|
|
|
|
|
|
|
|
||||
Restructuring charges
|
|
—
|
|
|
—
|
|
|
4,208
|
|
|||
Incremental general and administrative related to initial public offering
|
|
—
|
|
|
—
|
|
|
1,303
|
|
|||
Deferred revenue
|
|
(2,086
|
)
|
|
(870
|
)
|
|
(660
|
)
|
|||
Cash interest expense
|
|
(14,817
|
)
|
|
(6,676
|
)
|
|
(5,483
|
)
|
|||
(Gain) loss on sales of assets, net
|
|
(931
|
)
|
|
(4,793
|
)
|
|
(4,873
|
)
|
|||
Estimated replacement capital expenditures
2
|
|
(13,500
|
)
|
|
(11,250
|
)
|
|
—
|
|
|||
Cash paid to noncontrolling interests
|
|
(120
|
)
|
|
(111
|
)
|
|
(208
|
)
|
|||
Preferred unit distributions
|
|
(5,042
|
)
|
|
(5,763
|
)
|
|
(11,562
|
)
|
|||
Distributable cash flow
|
|
273,265
|
|
|
232,817
|
|
|
233,717
|
|
|||
Net working interest capital expenditures
|
|
$
|
(39,477
|
)
|
|
(80,179
|
)
|
|
(54,244
|
)
|
||
Distributable cash flow after net working interest capital expenditures
|
|
$
|
233,788
|
|
|
$
|
152,638
|
|
|
$
|
179,473
|
|
1
|
On April 25, 2016, the Compensation Committee of the board of directors of our general partner approved a resolution to change the settlement feature of certain employee long-term incentive compensation plans from cash to equity. As a result of the modification, $10.1 million of cash-settled liabilities were reclassified to equity-settled liabilities during the second quarter of 2016.
|
2
|
On August 3, 2016, the board of directors of our general partner established a replacement capital expenditures estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017; there was no established estimate of replacement capital expenditures prior to this period. On June 8, 2017, the board of directors of our general partner established a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018.
|
|
|
Year Ended December 31,
|
|||||||||||||
|
|
2017
|
|
2016
|
|
Variance
|
|||||||||
|
|
(dollars in thousands, except for realized prices and per BOE data)
|
|||||||||||||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate (MBbls)
|
|
3,552
|
|
|
3,680
|
|
|
(128
|
)
|
|
(3.5
|
)%
|
|||
Natural gas (MMcf)
1
|
|
59,779
|
|
|
47,498
|
|
|
12,281
|
|
|
25.9
|
%
|
|||
Equivalents (MBoe)
|
|
13,515
|
|
|
11,596
|
|
|
$
|
1,919
|
|
|
16.5
|
%
|
||
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate sales
|
|
$
|
169,728
|
|
|
$
|
142,382
|
|
|
$
|
27,346
|
|
|
19.2
|
%
|
Natural gas and natural gas liquids sales
1
|
|
190,967
|
|
|
122,836
|
|
|
68,131
|
|
|
55.5
|
%
|
|||
Gain (loss) on commodity derivative instruments
|
|
26,902
|
|
|
(36,464
|
)
|
|
63,366
|
|
|
(173.8
|
)%
|
|||
Lease bonus and other income
|
|
42,062
|
|
|
32,079
|
|
|
9,983
|
|
|
31.1
|
%
|
|||
Total revenue
|
|
$
|
429,659
|
|
|
$
|
260,833
|
|
|
$
|
168,826
|
|
|
64.7
|
%
|
Realized prices, without derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate ($/Bbl)
|
|
$
|
47.78
|
|
|
$
|
38.69
|
|
|
$
|
9.09
|
|
|
23.5
|
%
|
Natural gas ($/Mcf)
1
|
|
$
|
3.19
|
|
|
$
|
2.59
|
|
|
$
|
0.60
|
|
|
23.2
|
%
|
Equivalents ($/Boe)
|
|
$
|
26.69
|
|
|
$
|
22.87
|
|
|
$
|
3.82
|
|
|
16.7
|
%
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Lease operating expense
|
|
$
|
17,280
|
|
|
$
|
18,755
|
|
|
$
|
(1,475
|
)
|
|
(7.9
|
)%
|
Production costs and ad valorem taxes
|
|
47,474
|
|
|
35,464
|
|
|
12,010
|
|
|
33.9
|
%
|
|||
Exploration expense
|
|
618
|
|
|
645
|
|
|
(27
|
)
|
|
(4.2
|
)%
|
|||
Depreciation, depletion, and amortization
|
|
114,534
|
|
|
102,487
|
|
|
12,047
|
|
|
11.8
|
%
|
|||
Impairment of oil and natural gas properties
|
|
—
|
|
|
6,775
|
|
|
(6,775
|
)
|
|
(100.0
|
)%
|
|||
General and administrative
|
|
77,574
|
|
|
73,139
|
|
|
4,435
|
|
|
6.1
|
%
|
|
|
Year Ended December 31,
|
|||||||||||||
|
|
2016
|
|
2015
|
|
Variance
|
|||||||||
|
|
(dollars in thousands, except for realized prices and per BOE data)
|
|||||||||||||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate (MBbls)
|
|
3,680
|
|
|
3,565
|
|
|
115
|
|
|
3.2
|
%
|
|||
Natural gas (MMcf)
1
|
|
47,498
|
|
|
41,389
|
|
|
6,109
|
|
|
14.8
|
%
|
|||
Equivalents (MBoe)
|
|
11,596
|
|
|
10,463
|
|
|
$
|
1,133
|
|
|
10.8
|
%
|
||
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate sales
|
|
$
|
142,382
|
|
|
$
|
163,538
|
|
|
$
|
(21,156
|
)
|
|
(12.9
|
)%
|
Natural gas and natural gas liquids sales
1
|
|
122,836
|
|
|
116,018
|
|
|
6,818
|
|
|
5.9
|
%
|
|||
Gain (loss) on commodity derivative instruments
|
|
(36,464
|
)
|
|
90,288
|
|
|
(126,752
|
)
|
|
(140.4
|
)%
|
|||
Lease bonus and other income
|
|
32,079
|
|
|
23,080
|
|
|
8,999
|
|
|
39.0
|
%
|
|||
Total revenue
|
|
$
|
260,833
|
|
|
$
|
392,924
|
|
|
$
|
(132,091
|
)
|
|
(33.6
|
)%
|
Realized prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Oil and condensate ($/Bbl)
|
|
$
|
38.69
|
|
|
$
|
45.87
|
|
|
$
|
(7.18
|
)
|
|
(15.7
|
)%
|
Natural gas ($/Mcf)
1
|
|
$
|
2.59
|
|
|
$
|
2.80
|
|
|
$
|
(0.21
|
)
|
|
(7.5
|
)%
|
Equivalents ($/Boe)
|
|
$
|
22.87
|
|
|
$
|
26.72
|
|
|
$
|
(3.85
|
)
|
|
(14.4
|
)%
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Lease operating expense
|
|
$
|
18,755
|
|
|
$
|
21,583
|
|
|
$
|
(2,828
|
)
|
|
(13.1
|
)%
|
Production costs and ad valorem taxes
|
|
35,464
|
|
|
35,767
|
|
|
(303
|
)
|
|
(0.8
|
)%
|
|||
Exploration expense
|
|
645
|
|
|
2,592
|
|
|
(1,947
|
)
|
|
(75.1
|
)%
|
|||
Depreciation, depletion, and amortization
|
|
102,487
|
|
|
104,298
|
|
|
(1,811
|
)
|
|
(1.7
|
)%
|
|||
Impairment of oil and natural gas properties
|
|
6,775
|
|
|
249,569
|
|
|
(242,794
|
)
|
|
(97.3
|
)%
|
|||
General and administrative
|
|
73,139
|
|
|
77,175
|
|
|
(4,036
|
)
|
|
(5.2
|
)%
|
1
|
As a mineral-and-royalty-interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(in thousands)
|
||||||||||
Cash flows provided by operating activities
|
|
$
|
281,852
|
|
|
$
|
196,656
|
|
|
$
|
284,735
|
|
Cash flows used in investing activities
|
|
(454,249
|
)
|
|
(221,542
|
)
|
|
(90,998
|
)
|
|||
Cash flows provided by (used in) financing activities
|
|
168,267
|
|
|
21,425
|
|
|
(195,307
|
)
|
|
|
|
|
Payments due by period
|
||||||||||||||||
|
|
Total
|
|
Less Than 1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More Than 5 Years
|
||||||||||
Credit facility
|
|
$
|
388,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
388,000
|
|
|
$
|
—
|
|
Operating lease obligations
|
|
1,708
|
|
|
1,654
|
|
|
54
|
|
|
—
|
|
|
—
|
|
|||||
Purchase commitments
|
|
1,017
|
|
|
856
|
|
|
161
|
|
|
—
|
|
|
—
|
|
|||||
Total
|
|
$
|
390,725
|
|
|
$
|
2,510
|
|
|
$
|
215
|
|
|
$
|
388,000
|
|
|
$
|
—
|
|
Exhibit Number
|
|
Description
|
|
|
|
2.1
**
|
|
Purchase and Sale Agreement, dated as of November 22, 2017, by and among Noble Energy Inc., Noble Energy Wyco, LLC, Noble Energy US Holdings, LLC, Rosetta Resources Operating LP, and Black Stone Minerals Company, L.P. (incorporated herein by reference to Exhibit 2.1 of Black Stone Minerals, L.P.'s Current Report of Form 8-K filed on November 29, 2017 (SEC File No. 001-37362))
|
|
|
|
|
Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.1 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
|
|
Certificate of Amendment to Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.2 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
|
|
First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated May 6, 2015, by and among Black Stone Minerals GP, L.L.C. and Black Stone Minerals Company, L.P., (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (SEC File No. 001-37362)).
|
|
|
|
|
|
Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of April 15, 2016 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on April 19, 2016 (SEC File No. 001-37362)).
|
|
|
|
|
|
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of November 28, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 29, 2017 (SEC File No. 001-37362)).
|
|
|
|
|
|
Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of December 11, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12, 2017 (SEC File No. 001-37362)).
|
|
|
|
|
|
Registration Rights Agreement, dated as of November 28, 2017, by and between Black Stone Minerals, L.P. and Minerals Royalties One, L.L.C. (incorporated herein by reference to Exhibit 4.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12, 2017 (SEC File No. 001-37362)).
|
|
|
|
|
10.1
^
|
|
Black Stone Minerals, L.P. Long-Term Incentive Plan, dated May 6, 2015, by Black Stone Minerals GP, L.L.C. (incorporated herein by reference to Exhibit 10.1 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (SEC File No. 001-37362)).
|
|
|
|
|
Third Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A. and Compass Bank, as Co-Syndication Agents, Wells Fargo Bank, N.A. and Amegy Bank National Association, as Co-Documentation Agents, and a syndicate of lenders dated as of January 23, 2015 (incorporated herein by reference to Exhibit 10.2 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
|
|
Fourth Amended and Restated Credit Agreement, among Black Stone Minerals Company, L.P., as Borrower, Black Stone Minerals, L.P., as Parent MLP, Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A. and Compass Bank, as Co-Syndication Agents, ZB Bank, N.A. DBA and Amegy Bank National Association, as Documentation Agent, and the lenders signatory thereto, dated as of November 1, 2017 (incorporated herein by reference to Exhibit 10.1 to Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 7, 2017 (SEC File No. 001-37362)).
|
|
|
|
|
10.4
*#
|
|
First Amendment to Fourth Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender, Bank of America, N.A. and Compass Bank, as Co-Syndication Agents, ZB Bank, N.A., DBA Amegy Bank, National Association, as Documentation Agent, and a syndicate of lenders dated as of February 7, 2018.
|
|
|
|
10.5
^
|
|
Employment Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective as of April 1, 2009 (incorporated herein by reference to Exhibit 10.3 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.6
^
|
|
First Amendment to Employment Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective as of June 25, 2014 (incorporated herein by reference to Exhibit 10.4 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.7
^
|
|
Black Stone Minerals Company, L.P. 2012 Executive Incentive Plan (incorporated herein by reference to Exhibit 10.5 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.8
^
|
|
Restricted Unit Award Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective as of January 1, 2012 (incorporated herein by reference to Exhibit 10.6 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.9
^
|
|
Restricted Unit Award Agreement by and between Black Stone Minerals Company, L.P. and Marc Carroll effective as of January 1, 2012 (incorporated herein by reference to Exhibit 10.7 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.10
^
|
|
Restricted Unit Award Agreement by and between Black Stone Minerals Company, L.P. and Holbrook F. Dorn effective as of January 1, 2012 (incorporated herein by reference to Exhibit 10.8 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.11
^
|
|
Form of IPO Award Grant Notice and Award Agreement for Senior Management (Restricted Units) (incorporated herein by reference to Exhibit 10.9 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.12
^
|
|
Form of IPO Award Grant Notice and Award Agreement for Senior Management (Performance Units) (incorporated herein by reference to Exhibit 10.10 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.13
^
|
|
Form of Non-Employee Director Unit Grant Notice and Award Agreement (incorporated herein by reference to Exhibit 10.11 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.14
^
|
|
Form of Severance Agreement for Thomas L. Carter, Jr. (incorporated herein by reference to Exhibit 10.12 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.15
^
|
|
Form of Severance Agreement for Senior Vice Presidents (incorporated herein by reference to Exhibit 10.13 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).
|
|
|
|
10.16
^
|
|
Form of LTI Award Grant Notice and LTI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.2 to Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on February 19, 2016 (SEC File No. 001-37362).
|
|
|
|
10.17
*
|
|
Form of STI Award Letter (Leadership) under the Black Stone Minerals, L.P. Long-Term Incentive Plan.
|
|
|
|
10.18
^
|
|
Separation and Consulting Agreement and General Release of Claims, dated as of November 21, 2016, by and among Marc Carroll, Black Stone Natural Resources Management Company, and Black Stone Minerals GP, L.L.C. (incorporated herein by reference to Exhibit 10.1 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 28, 2016 (SEC File No. 001-37362)).
|
|
|
|
|
Series B Preferred Unit Purchase Agreement, dated as of November 22, 2017, by and between Black Stone Minerals, L.P. and Mineral Royalties One, L.L.C. (incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12, 2017 (SEC File No. 001-37362)).
|
|
|
|
|
21.1
*
|
|
List of Subsidiaries of Black Stone Minerals, L.P.
|
|
|
|
23.1
*
|
|
Consent of Ernst & Young LLP
|
|
|
|
23.2
*
|
|
Consent of BDO USA, LLP
|
|
|
|
23.3
*
|
|
Consent of Netherland, Sewell & Associates, Inc.
|
|
|
|
31.1
*
|
|
Certification of Chief Executive Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
|
31.2
*
|
|
Certification of Chief Financial Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
|
32.1
*
|
|
Certification of Chief Executive Officer and Chief Financial Officer of Black Stone Minerals, L.P. pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
|
99.1
*
|
|
Report of Netherland, Sewell & Associates, Inc.
|
|
|
|
101.INS*
|
|
XBRL Instance Document.
|
|
|
|
101.SCH*
|
|
XBRL Taxonomy Schema Document.
|
|
|
|
101.CAL*
|
|
XBRL Taxonomy Calculation Linkbase Document.
|
|
|
|
101.DEF*
|
|
XBRL Taxonomy Definition Linkbase Document.
|
|
|
|
101.LAB*
|
|
XBRL Taxonomy Label Linkbase Document.
|
|
|
|
101.PRE*
|
|
XBRL Taxonomy Presentation Linkbase Document.
|
*
|
Filed herewith.
|
|
**
|
Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Partnership agrees to furnish supplementally a copy of the omitted schedules and exhibits to the SEC upon request.
|
|
^
|
Management contract or compensatory plan or arrangement.
|
|
#
|
The agreement filed herewith is a corrected version of the agreement previously filed as Exhibit 10.1 to the Current Report on Form 8-K filed on February 12, 2018.
|
|
|
|
|
BLACK STONE MINERALS, L.P.
|
|
||
|
|
|
|
|
|
|
|
|
|
By:
|
|
Black Stone Minerals GP, L.L.C.,
its general partner
|
|
||
|
|
|
|
|
|
|
|
February 28, 2018
|
|
By:
|
|
/s/ Thomas L. Carter, Jr.
|
|
||
|
|
|
|
Thomas L. Carter, Jr.
|
|
||
|
|
|
|
President, Chief Executive Officer, and Chairman
|
|
||
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
|
|
|
|
/s/ Thomas L. Carter, Jr.
|
|
President, Chief Executive Officer, and Chairman
|
|
February 28, 2018
|
Thomas L. Carter, Jr.
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
/s/ Jeffrey P. Wood
|
|
Senior Vice President and Chief Financial Officer
|
|
February 28, 2018
|
Jeffrey P. Wood
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
/s/ Dawn K. Smajstrla
|
|
Vice President and Chief Accounting Officer
|
|
February 28, 2018
|
Dawn K. Smajstrla
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
/s/ William G. Bardel
|
|
Director
|
|
February 28, 2018
|
William G. Bardel
|
|
|
|
|
|
|
|
|
|
/s/ Carin M. Barth
|
|
Director
|
|
February 28, 2018
|
Carin M. Barth
|
|
|
|
|
|
|
|
|
|
/s/ D. Mark DeWalch
|
|
Director
|
|
February 28, 2018
|
D. Mark DeWalch
|
|
|
|
|
|
|
|
|
|
/s/ Ricky J. Haeflinger
|
|
Director
|
|
February 28, 2018
|
Ricky J. Haeflinger
|
|
|
|
|
|
|
|
|
|
/s/ Jerry V. Kyle, Jr.
|
|
Director
|
|
February 28, 2018
|
Jerry V. Kyle, Jr.
|
|
|
|
|
|
|
|
|
|
/s/ Michael C. Linn
|
|
Director
|
|
February 28, 2018
|
Michael C. Linn
|
|
|
|
|
|
|
|
|
|
/s/ John H. Longmaid
|
|
Director
|
|
February 28, 2018
|
John H. Longmaid
|
|
|
|
|
|
|
|
|
|
/s/ William N. Mathis
|
|
Director
|
|
February 28, 2018
|
William N. Mathis
|
|
|
|
|
|
|
|
|
|
/s/ William E. Randall
|
|
Director
|
|
February 28, 2018
|
William E. Randall
|
|
|
|
|
|
|
|
|
|
/s/ Alexander D. Stuart
|
|
Director
|
|
February 28, 2018
|
Alexander D. Stuart
|
|
|
|
|
|
|
|
|
|
/s/ Allison K. Thacker
|
|
Director
|
|
February 28, 2018
|
Allison K. Thacker
|
|
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
||
|
|
|
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
ASSETS
|
|
|
|
||||
CURRENT ASSETS
|
|
|
|
|
|
||
Cash and cash equivalents
|
$
|
5,642
|
|
|
$
|
9,772
|
|
Accounts receivable
|
80,695
|
|
|
68,181
|
|
||
Commodity derivative assets
|
94
|
|
|
—
|
|
||
Prepaid expenses and other current assets
|
1,212
|
|
|
1,036
|
|
||
TOTAL CURRENT ASSETS
|
87,643
|
|
|
78,989
|
|
||
PROPERTY AND EQUIPMENT
|
|
|
|
|
|
||
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $988,720 and $605,736 at December 31, 2017 and 2016, respectively
|
3,247,613
|
|
|
2,697,073
|
|
||
Accumulated depreciation, depletion, amortization, and impairment
|
(1,766,842
|
)
|
|
(1,652,930
|
)
|
||
Oil and natural gas properties, net
|
1,480,771
|
|
|
1,044,143
|
|
||
Other property and equipment, net of accumulated depreciation of $14,433 and $14,327 at December 31, 2017 and 2016, respectively
|
559
|
|
|
528
|
|
||
NET PROPERTY AND EQUIPMENT
|
1,481,330
|
|
|
1,044,671
|
|
||
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS
|
7,478
|
|
|
5,167
|
|
||
TOTAL ASSETS
|
$
|
1,576,451
|
|
|
$
|
1,128,827
|
|
LIABILITIES, MEZZANINE EQUITY, AND EQUITY
|
|
|
|
|
|
||
CURRENT LIABILITIES
|
|
|
|
|
|
||
Accounts payable
|
$
|
2,464
|
|
|
$
|
4,142
|
|
Accrued liabilities
|
52,631
|
|
|
50,952
|
|
||
Commodity derivative liabilities
|
4,222
|
|
|
16,237
|
|
||
Other current liabilities
|
417
|
|
|
—
|
|
||
TOTAL CURRENT LIABILITIES
|
59,734
|
|
|
71,331
|
|
||
LONG-TERM LIABILITIES
|
|
|
|
|
|
||
Credit facility
|
388,000
|
|
|
316,000
|
|
||
Accrued incentive compensation
|
3,648
|
|
|
1,485
|
|
||
Commodity derivative liabilities
|
1,263
|
|
|
482
|
|
||
Deferred revenue
|
—
|
|
|
518
|
|
||
Asset retirement obligations
|
14,092
|
|
|
13,350
|
|
||
Other long-term liabilities
|
19,171
|
|
|
—
|
|
||
TOTAL LIABILITIES
|
485,908
|
|
|
403,166
|
|
||
COMMITMENTS AND CONTINGENCIES (Note 11)
|
|
|
|
|
|
||
MEZZANINE EQUITY
|
|
|
|
|
|
||
Partners' equity
—
Series A redeemable preferred units, 26 and 53 units outstanding at December 31, 2017 and 2016, respectively
|
27,028
|
|
|
54,015
|
|
||
Partners' equity
—
Series B cumulative convertible preferred units, 14,711 and 0 units outstanding at December 31, 2017 and 2016, respectively
|
295,394
|
|
|
—
|
|
||
EQUITY
|
|
|
|
|
|
||
Partners' equity
—
general partner interest
|
—
|
|
|
—
|
|
||
Partners' equity
—
common units, 103,456 and 95,721 units outstanding at December 31, 2017 and 2016, respectively
|
603,116
|
|
|
489,023
|
|
||
Partners' equity
—
subordinated units, 95,388 and 95,164 units outstanding at December 31, 2017 and 2016, respectively
|
164,138
|
|
|
181,602
|
|
||
Noncontrolling interests
|
867
|
|
|
1,021
|
|
||
TOTAL EQUITY
|
768,121
|
|
|
671,646
|
|
||
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY
|
$
|
1,576,451
|
|
|
$
|
1,128,827
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
REVENUE
|
|
|
|
|
|
|
|
|
|||
Oil and condensate sales
|
$
|
169,728
|
|
|
$
|
142,382
|
|
|
$
|
163,538
|
|
Natural gas and natural gas liquids sales
|
190,967
|
|
|
122,836
|
|
|
116,018
|
|
|||
Gain (loss) on commodity derivative instruments
|
26,902
|
|
|
(36,464
|
)
|
|
90,288
|
|
|||
Lease bonus and other income
|
42,062
|
|
|
32,079
|
|
|
23,080
|
|
|||
TOTAL REVENUE
|
429,659
|
|
|
260,833
|
|
|
392,924
|
|
|||
OPERATING (INCOME) EXPENSE
|
|
|
|
|
|
|
|
|
|||
Lease operating expense
|
17,280
|
|
|
18,755
|
|
|
21,583
|
|
|||
Production costs and ad valorem taxes
|
47,474
|
|
|
35,464
|
|
|
35,767
|
|
|||
Exploration expense
|
618
|
|
|
645
|
|
|
2,592
|
|
|||
Depreciation, depletion and amortization
|
114,534
|
|
|
102,487
|
|
|
104,298
|
|
|||
Impairment of oil and natural gas properties
|
—
|
|
|
6,775
|
|
|
249,569
|
|
|||
General and administrative
|
77,574
|
|
|
73,139
|
|
|
77,175
|
|
|||
Accretion of asset retirement obligations
|
1,026
|
|
|
892
|
|
|
1,075
|
|
|||
(Gain) loss on sale of assets, net
|
(931
|
)
|
|
(4,793
|
)
|
|
(4,873
|
)
|
|||
Other expense
|
—
|
|
|
—
|
|
|
1,593
|
|
|||
TOTAL OPERATING EXPENSE
|
257,575
|
|
|
233,364
|
|
|
488,779
|
|
|||
INCOME (LOSS) FROM OPERATIONS
|
172,084
|
|
|
27,469
|
|
|
(95,855
|
)
|
|||
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
|||
Interest and investment income
|
49
|
|
|
656
|
|
|
58
|
|
|||
Interest expense
|
(15,694
|
)
|
|
(7,547
|
)
|
|
(6,418
|
)
|
|||
Other income (expense)
|
714
|
|
|
(390
|
)
|
|
910
|
|
|||
TOTAL OTHER EXPENSE
|
(14,931
|
)
|
|
(7,281
|
)
|
|
(5,450
|
)
|
|||
NET INCOME (LOSS)
|
157,153
|
|
|
20,188
|
|
|
(101,305
|
)
|
|||
Net loss attributable to Predecessor
|
—
|
|
|
—
|
|
|
(450
|
)
|
|||
Net income attributable to noncontrolling interests subsequent to initial public offering
|
34
|
|
|
12
|
|
|
1,260
|
|
|||
Distributions on Series A redeemable preferred units subsequent to initial public offering
|
(3,117
|
)
|
|
(5,763
|
)
|
|
(7,522
|
)
|
|||
Distributions on Series B cumulative convertible preferred units
|
(1,925
|
)
|
|
—
|
|
|
—
|
|
|||
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING
|
$
|
152,145
|
|
|
$
|
14,437
|
|
|
$
|
(108,017
|
)
|
ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
|
|
|
|
|
|
|
|
|
|||
General partner interest
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Common units
|
98,389
|
|
|
24,669
|
|
|
(54,326
|
)
|
|||
Subordinated units
|
53,756
|
|
|
(10,232
|
)
|
|
(53,691
|
)
|
|||
|
$
|
152,145
|
|
|
$
|
14,437
|
|
|
$
|
(108,017
|
)
|
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
|
|
|
|
|
|
|
|
|
|||
Per common unit (basic)
|
$
|
1.01
|
|
|
$
|
0.26
|
|
|
$
|
(0.56
|
)
|
Weighted average common units outstanding (basic)
|
97,400
|
|
|
96,073
|
|
|
96,182
|
|
|||
Per subordinated unit (basic)
|
$
|
0.56
|
|
|
$
|
(0.11
|
)
|
|
$
|
(0.56
|
)
|
Weighted average subordinated units outstanding (basic)
|
95,149
|
|
|
95,138
|
|
|
95,057
|
|
|||
Per common unit (diluted)
|
$
|
1.01
|
|
|
$
|
0.26
|
|
|
$
|
(0.56
|
)
|
Weighted average common units outstanding (diluted)
|
97,400
|
|
|
96,243
|
|
|
96,182
|
|
|||
Per subordinated unit (diluted)
|
$
|
0.56
|
|
|
$
|
(0.11
|
)
|
|
$
|
(0.56
|
)
|
Weighted average subordinated units outstanding (diluted)
|
95,149
|
|
|
95,138
|
|
|
95,057
|
|
|||
DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING:
|
|
|
|
|
|
|
|
|
|||
Per common unit
|
$
|
1.20
|
|
|
$
|
1.10
|
|
|
$
|
0.42
|
|
Per subordinated unit
|
$
|
0.79
|
|
|
$
|
0.74
|
|
|
$
|
0.42
|
|
|
Predecessor
|
|
Black Stone Minerals, L.P.
|
||||||||||||||||||||||||
|
Predecessor
units
|
|
Partners'
equity
|
|
Common
units
|
|
Subordinated
units
|
|
Partners'
equity—
common
units
|
|
Partners'
equity—
subordinated
units
|
|
Noncontrolling
interests
|
|
Total
equity
|
||||||||||||
BALANCE AT DECEMBER 31, 2014
|
164,484
|
|
|
653,217
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
653,217
|
|
Conversion of Predecessor redeemable preferred units
|
2,750
|
|
|
39,240
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
39,240
|
|
||||
Restricted Predecessor units granted
|
562
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Repurchases of Predecessor units
|
(164
|
)
|
|
(3,015
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,015
|
)
|
||||
Distributions to Predecessor unitholders and noncontrolling interests
|
—
|
|
|
(73,205
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(73,205
|
)
|
||||
Distributions on Predecessor redeemable preferred units
|
—
|
|
|
(4,040
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,040
|
)
|
||||
Net income attributable to Predecessor
|
—
|
|
|
450
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
450
|
|
||||
Allocation of Predecessor units and equity
|
(167,632
|
)
|
|
(612,647
|
)
|
|
72,575
|
|
|
95,057
|
|
|
264,235
|
|
|
345,875
|
|
|
2,537
|
|
|
—
|
|
||||
Issuance of common units for initial public offering, net of offering costs
|
—
|
|
|
—
|
|
|
22,500
|
|
|
—
|
|
|
391,500
|
|
|
—
|
|
|
—
|
|
|
391,500
|
|
||||
Restricted common units granted, net of forfeitures
|
—
|
|
|
—
|
|
|
1,087
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Equity-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14,181
|
|
|
3,819
|
|
|
—
|
|
|
18,000
|
|
||||
Distributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(40,783
|
)
|
|
(40,304
|
)
|
|
(133
|
)
|
|
(81,220
|
)
|
||||
Charges to partners' equity for accrued distribution equivalent rights
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(159
|
)
|
|
—
|
|
|
—
|
|
|
(159
|
)
|
||||
Net loss subsequent to initial public offering
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(50,543
|
)
|
|
(49,952
|
)
|
|
(1,260
|
)
|
|
(101,755
|
)
|
||||
Distributions on Series A redeemable preferred units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,783
|
)
|
|
(3,739
|
)
|
|
—
|
|
|
(7,522
|
)
|
||||
BALANCE AT DECEMBER 31, 2015
|
—
|
|
|
—
|
|
|
96,162
|
|
|
95,057
|
|
|
574,648
|
|
|
255,699
|
|
|
1,144
|
|
|
831,491
|
|
||||
Conversion of Series A redeemable preferred units
|
—
|
|
|
—
|
|
|
184
|
|
|
241
|
|
|
2,625
|
|
|
3,439
|
|
|
—
|
|
|
6,064
|
|
||||
Repurchases of common and subordinated units
|
—
|
|
|
—
|
|
|
(1,618
|
)
|
|
(78
|
)
|
|
(27,436
|
)
|
|
—
|
|
|
—
|
|
|
(27,436
|
)
|
||||
Restricted common and subordinated units granted, net of forfeitures
|
—
|
|
|
—
|
|
|
993
|
|
|
(56
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Equity-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21,022
|
|
|
2,823
|
|
|
—
|
|
|
23,845
|
|
||||
Distributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(105,817
|
)
|
|
(70,127
|
)
|
|
(111
|
)
|
|
(176,055
|
)
|
||||
Charges to partners' equity for accrued distribution equivalent rights
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(688
|
)
|
|
—
|
|
|
—
|
|
|
(688
|
)
|
||||
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
27,565
|
|
|
(7,365
|
)
|
|
(12
|
)
|
|
20,188
|
|
||||
Distributions on Series A redeemable preferred units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,896
|
)
|
|
(2,867
|
)
|
|
—
|
|
|
(5,763
|
)
|
||||
BALANCE AT DECEMBER 31, 2016
|
—
|
|
|
—
|
|
|
95,721
|
|
|
95,164
|
|
|
489,023
|
|
|
181,602
|
|
|
1,021
|
|
|
671,646
|
|
||||
Conversion of Series A redeemable preferred units
|
—
|
|
|
—
|
|
|
201
|
|
|
263
|
|
|
2,868
|
|
|
3,756
|
|
|
—
|
|
|
6,624
|
|
||||
Repurchases of common and subordinated units
|
—
|
|
|
—
|
|
|
(446
|
)
|
|
(39
|
)
|
|
(7,893
|
)
|
|
(292
|
)
|
|
—
|
|
|
(8,185
|
)
|
||||
Issuance of common units, net of offering costs
|
—
|
|
|
—
|
|
|
2,002
|
|
|
—
|
|
|
32,458
|
|
|
—
|
|
|
—
|
|
|
32,458
|
|
||||
Issuance of units for property acquisitions
|
—
|
|
|
—
|
|
|
4,348
|
|
|
—
|
|
|
71,723
|
|
|
—
|
|
|
—
|
|
|
71,723
|
|
||||
Restricted units granted, net of forfeitures
|
—
|
|
|
—
|
|
|
1,630
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Equity-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
39,205
|
|
|
152
|
|
|
—
|
|
|
39,357
|
|
||||
Distributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(119,963
|
)
|
|
(74,836
|
)
|
|
(120
|
)
|
|
(194,919
|
)
|
||||
Charges to partners' equity for accrued distribution equivalent rights
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,694
|
)
|
|
—
|
|
|
—
|
|
|
(2,694
|
)
|
||||
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
101,891
|
|
|
55,296
|
|
|
(34
|
)
|
|
157,153
|
|
||||
Distributions on Series A redeemable preferred units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,577
|
)
|
|
(1,540
|
)
|
|
—
|
|
|
(3,117
|
)
|
||||
Distributions on Series B cumulative convertible preferred units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,925
|
)
|
|
—
|
|
|
—
|
|
|
(1,925
|
)
|
||||
BALANCE AT DECEMBER 31, 2017
|
—
|
|
|
—
|
|
|
103,456
|
|
|
95,388
|
|
|
$
|
603,116
|
|
|
$
|
164,138
|
|
|
$
|
867
|
|
|
$
|
768,121
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|||
Net income (loss)
|
$
|
157,153
|
|
|
$
|
20,188
|
|
|
$
|
(101,305
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|||
Depreciation, depletion, and amortization
|
114,534
|
|
|
102,487
|
|
|
104,298
|
|
|||
Impairment of oil and natural gas properties
|
—
|
|
|
6,775
|
|
|
249,569
|
|
|||
Accretion of asset retirement obligations
|
1,026
|
|
|
892
|
|
|
1,075
|
|
|||
Amortization of deferred charges
|
877
|
|
|
871
|
|
|
935
|
|
|||
(Gain) loss on commodity derivative instruments
|
(26,902
|
)
|
|
36,464
|
|
|
(90,288
|
)
|
|||
Net cash received (paid) on settlement of commodity derivative instruments
|
15,211
|
|
|
44,789
|
|
|
63,225
|
|
|||
Equity-based compensation
|
33,044
|
|
|
43,138
|
|
|
18,000
|
|
|||
(Gain) loss on sale of assets, net
|
(931
|
)
|
|
(4,793
|
)
|
|
(4,873
|
)
|
|||
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|||||
Accounts receivable
|
(6,084
|
)
|
|
(29,759
|
)
|
|
33,586
|
|
|||
Prepaid expenses and other current assets
|
(177
|
)
|
|
(180
|
)
|
|
95
|
|
|||
Accounts payable and accrued liabilities
|
(3,585
|
)
|
|
(23,029
|
)
|
|
11,221
|
|
|||
Deferred revenue
|
(2,086
|
)
|
|
(870
|
)
|
|
(660
|
)
|
|||
Settlement of asset retirement obligations
|
(228
|
)
|
|
(317
|
)
|
|
(143
|
)
|
|||
NET CASH PROVIDED BY OPERATING ACTIVITIES
|
281,852
|
|
|
196,656
|
|
|
284,735
|
|
|||
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|||
Acquisitions of oil and natural gas properties
|
(425,667
|
)
|
|
(141,136
|
)
|
|
(62,278
|
)
|
|||
Additions to oil and natural gas properties
|
(58,648
|
)
|
|
(80,179
|
)
|
|
(54,244
|
)
|
|||
Purchases of other property and equipment
|
(207
|
)
|
|
(425
|
)
|
|
(181
|
)
|
|||
Proceeds from the sale of oil and natural gas properties
|
11,102
|
|
|
198
|
|
|
25,705
|
|
|||
Proceeds from farmouts of oil and natural gas properties
|
19,171
|
|
|
—
|
|
|
—
|
|
|||
NET CASH USED IN INVESTING ACTIVITIES
|
(454,249
|
)
|
|
(221,542
|
)
|
|
(90,998
|
)
|
|||
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|||
Proceeds from issuance of common units of Black Stone Minerals, L.P., net of offering costs
|
32,458
|
|
|
—
|
|
|
399,087
|
|
|||
Proceeds from issuance of Series B cumulative convertible preferred units of Black Stone Minerals, L.P., net of offering costs
|
293,469
|
|
|
—
|
|
|
—
|
|
|||
Distributions to Predecessor unitholders
|
—
|
|
|
—
|
|
|
(126,383
|
)
|
|||
Distributions to common and subordinated unitholders
|
(194,799
|
)
|
|
(175,943
|
)
|
|
(81,087
|
)
|
|||
Distributions to Series A redeemable preferred unitholders
|
(3,777
|
)
|
|
(6,385
|
)
|
|
(13,578
|
)
|
|||
Distributions to noncontrolling interests
|
(120
|
)
|
|
(111
|
)
|
|
(208
|
)
|
|||
Redemption of Series A redeemable preferred units
|
(19,704
|
)
|
|
(18,461
|
)
|
|
(40,747
|
)
|
|||
Repurchases of Predecessor units
|
—
|
|
|
—
|
|
|
(3,015
|
)
|
|||
Repurchases of common and subordinated units
|
(8,185
|
)
|
|
(27,436
|
)
|
|
—
|
|
|||
Borrowings under credit facility
|
292,500
|
|
|
349,000
|
|
|
245,600
|
|
|||
Repayments under credit facility
|
(220,500
|
)
|
|
(99,000
|
)
|
|
(573,600
|
)
|
|||
Debt issuance costs
|
(3,075
|
)
|
|
(239
|
)
|
|
(1,376
|
)
|
|||
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
|
168,267
|
|
|
21,425
|
|
|
(195,307
|
)
|
|||
NET CHANGE IN CASH AND CASH EQUIVALENTS
|
(4,130
|
)
|
|
(3,461
|
)
|
|
(1,570
|
)
|
|||
Cash and cash equivalents
—
beginning of the year
|
9,772
|
|
|
13,233
|
|
|
14,803
|
|
|||
Cash and cash equivalents
—
end of the year
|
$
|
5,642
|
|
|
$
|
9,772
|
|
|
$
|
13,233
|
|
SUPPLEMENTAL DISCLOSURE
|
|
|
|
|
|
||||||
Interest paid
|
$
|
14,761
|
|
|
$
|
6,535
|
|
|
$
|
5,478
|
|
NON-CASH ACTIVITIES
|
|
|
|
|
|
||||||
Accrued distributions payable to Predecessor unitholders
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(53,248
|
)
|
Conversion of Series A redeemable preferred units
|
(6,624
|
)
|
|
(6,064
|
)
|
|
(39,240
|
)
|
|||
Accrued distributions payable to Series A redeemable preferred unitholders
|
(660
|
)
|
|
(1,324
|
)
|
|
(2,016
|
)
|
|||
Accrued distributions payable to Series B cumulative convertible preferred unitholders
|
(1,925
|
)
|
|
—
|
|
|
—
|
|
|||
Additions to oil and natural gas properties financed through accounts payable and accrued liabilities
|
34,247
|
|
|
26,553
|
|
|
21,496
|
|
|||
Public offering costs capitalized and offset against proceeds from initial public offering
|
—
|
|
|
—
|
|
|
7,587
|
|
|||
Asset retirement obligations incurred and revisions in estimated costs
|
391
|
|
|
2,009
|
|
|
272
|
|
|||
Accrued distribution equivalent rights
|
2,694
|
|
|
847
|
|
|
159
|
|
|
As of December 31,
|
||||||
|
2017
|
|
2016
|
||||
Accrued liabilities:
|
(in thousands)
|
||||||
Accrued capital expenditures
|
$
|
28,711
|
|
|
$
|
17,775
|
|
Accrued incentive compensation
|
16,503
|
|
|
20,898
|
|
||
Accrued property taxes
|
4,090
|
|
|
3,175
|
|
||
Accrued other
|
3,327
|
|
|
9,104
|
|
||
Total accrued liabilities
|
$
|
52,631
|
|
|
$
|
50,952
|
|
•
|
The fair value (or intrinsic or calculated value if elected) of the modified award is the same as the value of the original award immediately before the original award was modified.
|
•
|
The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified.
|
•
|
The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified.
|
|
For the year ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in thousands)
|
||||||
Beginning asset retirement obligations
|
$
|
13,350
|
|
|
$
|
10,585
|
|
Liabilities incurred
|
308
|
|
|
2,009
|
|
||
Liabilities settled
|
(228
|
)
|
|
(317
|
)
|
||
Accretion expense
|
1,026
|
|
|
892
|
|
||
Revisions in estimated costs
|
83
|
|
|
181
|
|
||
Dispositions
|
(30
|
)
|
|
—
|
|
||
Ending asset retirement obligations
|
$
|
14,509
|
|
|
$
|
13,350
|
|
Current asset retirement obligations
|
$
|
417
|
|
|
$
|
—
|
|
Non-current asset retirement obligations
|
$
|
14,092
|
|
|
$
|
13,350
|
|
|
Assets Acquired
|
|
Cash Consideration Paid
|
|
Acquisition-Related Costs
1
|
||||||||||||||||||
|
Proved
|
|
Unproved
|
|
Net Working Capital
|
|
Total Fair Value
|
|
|
||||||||||||||
|
(in thousands)
|
||||||||||||||||||||||
Noble Assets
|
$
|
68,877
|
|
|
$
|
259,749
|
|
|
$
|
5,917
|
|
|
$
|
334,543
|
|
|
$
|
334,543
|
|
|
$
|
247
|
|
1
|
Acquisition-related costs were expensed and included in the general and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017.
|
|
For the Year Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in thousands, except per unit amounts)
|
||||||
Revenue and other income
|
$
|
468,103
|
|
|
$
|
288,772
|
|
Net income (loss)
|
$
|
178,970
|
|
|
$
|
33,264
|
|
Net income (loss) attributable to noncontrolling interests
|
34
|
|
|
12
|
|
||
Distributions on Series A redeemable preferred units
|
(3,117
|
)
|
|
(5,763
|
)
|
||
Distributions on Series B cumulative convertible preferred units
|
(21,000
|
)
|
|
(21,000
|
)
|
||
Net income (loss) attributable to the general partner and common and subordinated units
|
$
|
154,887
|
|
|
$
|
6,513
|
|
Allocation of net income (loss):
|
|
|
|
||||
General partner interest
|
—
|
|
|
—
|
|
||
Common units
|
99,776
|
|
|
20,696
|
|
||
Subordinated units
|
55,111
|
|
|
(14,183
|
)
|
||
|
$
|
154,887
|
|
|
$
|
6,513
|
|
Net income (loss) attributable to limited partners per common and subordinated unit:
|
|
|
|
||||
Per common unit (basic)
|
$
|
1.02
|
|
|
$
|
0.22
|
|
Per subordinated unit (basic)
|
$
|
0.58
|
|
|
$
|
(0.15
|
)
|
Per common unit (diluted)
|
$
|
1.02
|
|
|
$
|
0.22
|
|
Per subordinated unit (diluted)
|
$
|
0.58
|
|
|
$
|
(0.15
|
)
|
•
|
Adjustments to recognize incremental revenue, production costs and ad valorem taxes, and DD&A expense attributable to the Noble Assets.
|
•
|
Adjustment to recognize additional interest expense associated with the incremental borrowings under the Partnership's Credit Facility.
|
•
|
Adjustment to recognize the quarterly distribution associated with the issuance of
14,711,219
Series B cumulative convertible preferred units.
|
•
|
The Series B cumulative convertible preferred units were excluded from the calculation of pro forma diluted earnings per common unit for the periods presented above due to their antidilutive effect under the if-converted method; the Series B cumulative convertible preferred units do not have any impact to earnings per subordinated unit.
|
|
Assets Acquired
|
|
Consideration Paid
|
|
|
||||||||||||||||||||||
|
Proved
|
|
Unproved
|
|
Net Working Capital
|
|
Total Fair Value
|
|
Cash
|
|
Fair Value of Common Units Issued
|
|
Acquisition-Related Costs
1
|
||||||||||||||
|
(in thousands)
|
||||||||||||||||||||||||||
January
|
$
|
5,135
|
|
|
$
|
34,008
|
|
|
$
|
263
|
|
|
$
|
39,406
|
|
|
$
|
27,380
|
|
|
$
|
12,026
|
|
|
$
|
1,162
|
|
June
|
5,006
|
|
|
45,477
|
|
|
—
|
|
|
50,483
|
|
|
4,802
|
|
|
45,681
|
|
|
1,481
|
|
|||||||
August
|
3,277
|
|
|
9,984
|
|
|
—
|
|
|
13,261
|
|
|
4,289
|
|
|
8,972
|
|
|
107
|
|
|||||||
September
|
3,120
|
|
|
—
|
|
|
—
|
|
|
3,120
|
|
|
3,120
|
|
|
—
|
|
|
—
|
|
|||||||
Total fair value
|
$
|
16,538
|
|
|
$
|
89,469
|
|
|
$
|
263
|
|
|
$
|
106,270
|
|
|
$
|
39,591
|
|
|
$
|
66,679
|
|
|
$
|
2,750
|
|
1
|
Acquisition-related costs were expensed and included in the general and administrative expense line item of the 2017 consolidated statement of operations.
|
|
Assets Acquired
|
|
Consideration Paid
|
||||||||
|
Unproved
|
|
Cash
|
|
Fair Value of
Common Units Issued
|
||||||
|
(in thousands)
|
||||||||||
Q1 2017
|
$
|
21,189
|
|
|
$
|
21,017
|
|
|
$
|
172
|
|
Q2 2017
|
13,329
|
|
|
13,329
|
|
|
—
|
|
|||
Q3 2017
|
19,946
|
|
|
15,205
|
|
|
4,741
|
|
|||
Q4 2017
|
2,267
|
|
|
2,137
|
|
|
130
|
|
|||
Total acquired
|
$
|
56,731
|
|
|
$
|
51,688
|
|
|
$
|
5,043
|
|
|
Assets Acquired
|
|
Cash Consideration Paid
|
||||||||||||||||||||
|
Proved
|
|
Unproved
|
|
Net Working Capital
|
|
ARO
|
|
Total Fair Value
|
|
|||||||||||||
|
(in thousands)
|
||||||||||||||||||||||
June 2016
|
$
|
39,735
|
|
|
$
|
79,827
|
|
|
$
|
2,064
|
|
|
$
|
(50
|
)
|
|
$
|
121,576
|
|
|
$
|
121,576
|
|
|
|
|
|
As of December 31, 2017
|
||||||||||
Classification
|
|
Balance Sheet Location
|
|
Gross Fair
Value
|
|
Effect of
Counterparty Netting
|
|
Net Carrying
Value on
Balance Sheet
|
||||||
|
|
|
|
(in thousands)
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Current asset
|
|
Commodity derivative assets
|
|
$
|
10,713
|
|
|
$
|
(10,619
|
)
|
|
$
|
94
|
|
Long-term asset
|
|
Deferred charges and other long-term assets
|
|
1,392
|
|
|
(1,029
|
)
|
|
363
|
|
|||
Total assets
|
|
|
|
$
|
12,105
|
|
|
$
|
(11,648
|
)
|
|
$
|
457
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Current liability
|
|
Commodity derivative liabilities
|
|
$
|
14,841
|
|
|
$
|
(10,619
|
)
|
|
$
|
4,222
|
|
Long-term liability
|
|
Commodity derivative liabilities
|
|
2,292
|
|
|
(1,029
|
)
|
|
1,263
|
|
|||
Total liabilities
|
|
|
|
$
|
17,133
|
|
|
$
|
(11,648
|
)
|
|
$
|
5,485
|
|
|
|
|
|
As of December 31, 2016
|
||||||||||
Classification
|
|
Balance Sheet Location
|
|
Gross Fair
Value
|
|
Effect of
Counterparty
Netting
|
|
Net Carrying
Value on
Balance Sheet
|
||||||
|
|
|
|
(in thousands)
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Current asset
|
|
Commodity derivative assets
|
|
$
|
3,879
|
|
|
$
|
(3,879
|
)
|
|
$
|
—
|
|
Long-term asset
|
|
Deferred charges and other long-term assets
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total assets
|
|
|
|
$
|
3,879
|
|
|
$
|
(3,879
|
)
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Current liability
|
|
Commodity derivative liabilities
|
|
$
|
20,116
|
|
|
$
|
(3,879
|
)
|
|
$
|
16,237
|
|
Long-term liability
|
|
Commodity derivative liabilities
|
|
482
|
|
|
—
|
|
|
482
|
|
|||
Total liabilities
|
|
|
|
$
|
20,598
|
|
|
$
|
(3,879
|
)
|
|
$
|
16,719
|
|
|
|
For the year ended December 31,
|
||||||||||
Derivatives not designated as hedging instruments
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(in thousands)
|
||||||||||
Beginning fair value of commodity derivative instruments
|
|
$
|
(16,719
|
)
|
|
$
|
64,534
|
|
|
$
|
37,471
|
|
Gain (loss) on oil derivative instruments
|
|
(5,091
|
)
|
|
(15,998
|
)
|
|
57,681
|
|
|||
Gain (loss) on natural gas derivative instruments
|
|
31,993
|
|
|
(20,466
|
)
|
|
32,607
|
|
|||
Net cash received on settlements of oil derivative instruments
|
|
(10,901
|
)
|
|
(27,450
|
)
|
|
(41,786
|
)
|
|||
Net cash received on settlements of natural gas derivative instruments
|
|
(4,310
|
)
|
|
(17,339
|
)
|
|
(21,439
|
)
|
|||
Net change in fair value of commodity derivative instruments
|
|
11,691
|
|
|
(81,253
|
)
|
|
27,063
|
|
|||
Ending fair value of commodity derivative instruments
|
|
$
|
(5,028
|
)
|
|
$
|
(16,719
|
)
|
|
$
|
64,534
|
|
|
|
Volume (Bbl)
|
|
Weighted Average Price (per Bbl)
|
|
Range (per Bbl)
|
|||||||||
Period and Type of Contract
|
|
|
|
Low
|
|
High
|
|||||||||
Oil Swap Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
First quarter
|
|
729,000
|
|
|
$
|
54.36
|
|
|
$
|
52.09
|
|
|
$
|
57.15
|
|
Second quarter
|
|
736,000
|
|
|
54.33
|
|
|
52.09
|
|
|
56.75
|
|
|||
Third quarter
|
|
744,000
|
|
|
54.35
|
|
|
51.85
|
|
|
55.87
|
|
|||
Fourth quarter
|
|
749,000
|
|
|
54.24
|
|
|
51.85
|
|
|
55.87
|
|
|||
2019
|
|
|
|
|
|
|
|
|
|||||||
First quarter
|
|
165,000
|
|
|
$
|
53.58
|
|
|
$
|
52.82
|
|
|
$
|
54.02
|
|
Second quarter
|
|
165,000
|
|
|
53.58
|
|
|
52.82
|
|
|
54.02
|
|
|||
Third quarter
|
|
165,000
|
|
|
53.58
|
|
|
52.82
|
|
|
54.02
|
|
|||
Fourth quarter
|
|
165,000
|
|
|
53.58
|
|
|
52.82
|
|
|
54.02
|
|
|
|
Volume (MMBtu)
|
|
Weighted Average Price (per MMBtu)
|
|
Range (per MMBtu)
|
|||||||||
Period and Type of Contract
|
|
|
|
Low
|
|
High
|
|||||||||
Natural Gas Swap Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
2018
|
|
|
|
|
|
|
|
|
|||||||
First quarter
|
|
13,590,000
|
|
|
$
|
3.06
|
|
|
$
|
2.96
|
|
|
$
|
3.45
|
|
Second quarter
|
|
13,660,000
|
|
|
3.02
|
|
|
2.86
|
|
|
3.23
|
|
|||
Third quarter
|
|
13,600,000
|
|
|
3.01
|
|
|
2.90
|
|
|
3.23
|
|
|||
Fourth quarter
|
|
13,630,000
|
|
|
3.01
|
|
|
2.90
|
|
|
3.23
|
|
|||
2019
|
|
|
|
|
|
|
|
|
|||||||
First quarter
|
|
3,600,000
|
|
|
2.91
|
|
|
2.90
|
|
|
2.93
|
|
|||
Second quarter
|
|
3,600,000
|
|
|
2.91
|
|
|
2.90
|
|
|
2.93
|
|
|||
Third quarter
|
|
3,600,000
|
|
|
2.91
|
|
|
2.90
|
|
|
2.93
|
|
|||
Fourth quarter
|
|
3,600,000
|
|
|
2.91
|
|
|
2.90
|
|
|
2.93
|
|
|
|
Fair Value Measurements Using
|
|
Effect of
Counterparty
|
|
|
||||||||||||||
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Netting
|
|
Total
|
||||||||||
|
|
(In thousands)
|
||||||||||||||||||
As of December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Financial Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Commodity derivative instruments
|
|
$
|
—
|
|
|
$
|
12,105
|
|
|
$
|
—
|
|
|
$
|
(11,648
|
)
|
|
$
|
457
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Commodity derivative instruments
|
|
—
|
|
|
17,133
|
|
|
—
|
|
|
(11,648
|
)
|
|
5,485
|
|
|||||
As of December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Financial Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Commodity derivative instruments
|
|
$
|
—
|
|
|
$
|
3,879
|
|
|
$
|
—
|
|
|
$
|
(3,879
|
)
|
|
$
|
—
|
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Commodity derivative instruments
|
|
—
|
|
|
20,598
|
|
|
—
|
|
|
(3,879
|
)
|
|
16,719
|
|
|
|
Fair Value Measurements Using
|
|
Net Book
|
|
|
||||||||||||||
|
|
Level 1
|
|
Level 2
|
|
Level 3
1
|
|
Value
1
|
|
Impairment
|
||||||||||
|
|
(In thousands)
|
||||||||||||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Impaired oil and natural gas properties
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Impaired oil and natural gas properties
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,042
|
|
|
$
|
9,817
|
|
|
$
|
6,775
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Impaired oil and natural gas properties
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
156,689
|
|
|
$
|
406,258
|
|
|
$
|
249,569
|
|
|
|
Units
|
|
Weighted-Average Grant-Date Fair Value per Unit
|
||||||||||
|
|
Common
|
|
Subordinated
|
|
Common
|
|
Subordinated
|
||||||
Unvested at December 31, 2016
|
|
1,271,215
|
|
|
163,041
|
|
|
$
|
15.29
|
|
|
$
|
18.97
|
|
Granted
|
|
901,910
|
|
|
—
|
|
|
18.48
|
|
|
—
|
|
||
Vested
|
|
(602,764
|
)
|
|
(103,912
|
)
|
|
15.13
|
|
|
19.35
|
|
||
Converted
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
Forfeited
|
|
(28,303
|
)
|
|
—
|
|
|
17.64
|
|
|
—
|
|
||
Unvested at December 31, 2017
|
|
1,542,058
|
|
|
59,129
|
|
|
16.72
|
|
|
18.30
|
|
Performance units
|
|
Number of Units
|
|
Weighted-Average Grant-Date
Fair Value per Unit
|
|||
Unvested at December 31, 2016
|
|
1,156,419
|
|
|
$
|
14.94
|
|
Granted
|
|
438,288
|
|
|
17.99
|
|
|
Vested
|
|
—
|
|
|
—
|
|
|
Forfeited
|
|
(137,351
|
)
|
|
18.60
|
|
|
Unvested at December 31, 2017
|
|
1,457,356
|
|
|
15.51
|
|
|
|
Year Ended December 31,
|
||||||||||
Incentive compensation expense
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(In thousands)
|
||||||||||
Cash — long-term incentive plan
|
|
$
|
1,412
|
|
|
$
|
2,725
|
|
|
$
|
15,064
|
|
Equity-based compensation — restricted common and subordinated units
|
|
13,476
|
|
|
13,408
|
|
|
10,137
|
|
|||
Equity-based compensation — restricted performance units
|
|
17,367
|
|
|
18,518
|
|
|
4,743
|
|
|||
Board of Directors incentive plan
|
|
2,202
|
|
|
2,012
|
|
|
3,120
|
|
|||
Total incentive compensation expense
|
|
$
|
34,457
|
|
|
$
|
36,663
|
|
|
$
|
33,064
|
|
Year Ending December 31,
|
(in thousands)
|
||
2018
|
$
|
1,654
|
|
2019
|
38
|
|
|
2020
|
16
|
|
|
2021
|
—
|
|
|
Total
|
$
|
1,708
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(in thousands, except per unit amounts)
|
||||||||||
NET INCOME (LOSS)
|
|
$
|
157,153
|
|
|
$
|
20,188
|
|
|
$
|
(101,305
|
)
|
Net loss attributable to Predecessor
|
|
—
|
|
|
—
|
|
|
(450
|
)
|
|||
Net income attributable to noncontrolling interests subsequent to initial public offering
|
|
34
|
|
|
12
|
|
|
1,260
|
|
|||
Distributions on Series A redeemable preferred units subsequent to initial public offering
|
|
(3,117
|
)
|
|
(5,763
|
)
|
|
(7,522
|
)
|
|||
Distributions on Series B
cumulative convertible
preferred units
|
|
$
|
(1,925
|
)
|
|
—
|
|
|
—
|
|
||
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING
|
|
$
|
152,145
|
|
|
$
|
14,437
|
|
|
$
|
(108,017
|
)
|
ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
|
|
|
|
|
|
|
|
|
|
|||
General partner interest
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Common units
|
|
98,389
|
|
|
24,669
|
|
|
(54,326
|
)
|
|||
Subordinated units
|
|
53,756
|
|
|
(10,232
|
)
|
|
(53,691
|
)
|
|||
|
|
$
|
152,145
|
|
|
$
|
14,437
|
|
|
$
|
(108,017
|
)
|
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
|
|
|
|
|
|
|
|
|
|
|||
Per common unit (basic)
|
|
$
|
1.01
|
|
|
$
|
0.26
|
|
|
$
|
(0.56
|
)
|
Weighted average common units outstanding (basic)
|
|
97,400
|
|
|
96,073
|
|
|
96,182
|
|
|||
Per subordinated unit (basic)
|
|
$
|
0.56
|
|
|
$
|
(0.11
|
)
|
|
$
|
(0.56
|
)
|
Weighted average subordinated units outstanding (basic)
|
|
95,149
|
|
|
95,138
|
|
|
95,057
|
|
|||
Per common unit (diluted)
|
|
$
|
1.01
|
|
|
$
|
0.26
|
|
|
$
|
(0.56
|
)
|
Weighted average common units outstanding (diluted)
|
|
97,400
|
|
|
96,243
|
|
|
96,182
|
|
|||
Per subordinated unit (diluted)
|
|
$
|
0.56
|
|
|
$
|
(0.11
|
)
|
|
$
|
(0.56
|
)
|
Weighted average subordinated units outstanding (diluted)
|
|
95,149
|
|
|
95,138
|
|
|
95,057
|
|
•
|
first
, to the holders of the Series B cumulative convertible preferred units in an amount equal to
7%
per annum, subject to certain adjustments;
|
•
|
second
, to the holders of common units, until each common unit has received the applicable minimum quarterly distribution in the amounts specified below plus any arrearages from prior quarters; and
|
•
|
third
, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(in thousands)
|
||||||||||
Acquisition Costs of Properties:
1
|
|
|
|
|
|
|
||||||
Proved
|
|
$
|
96,596
|
|
|
$
|
40,242
|
|
|
$
|
2,302
|
|
Unproved
|
|
383,535
|
|
|
100,888
|
|
|
60,994
|
|
|||
Exploration Costs
|
|
618
|
|
|
645
|
|
|
2,592
|
|
|||
Development Costs
|
|
81,056
|
|
|
73,316
|
|
|
60,056
|
|
|||
Total
|
|
$
|
561,805
|
|
|
$
|
215,091
|
|
|
$
|
125,944
|
|
1.
|
See Note 4 – Oil and Natural Gas Properties Acquisitions for further discussion. Unproved properties also include purchases of leasehold prospects.
|
|
|
As of December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
|
|
(in thousands)
|
||||||
Proved properties
|
|
$
|
2,258,893
|
|
|
$
|
2,091,337
|
|
Unproved properties
|
|
988,720
|
|
|
605,736
|
|
||
Total
|
|
3,247,613
|
|
|
2,697,073
|
|
||
Accumulated depreciation, depletion, amortization, and impairment
|
|
(1,766,842
|
)
|
|
(1,652,930
|
)
|
||
Oil and natural gas properties, net
|
|
$
|
1,480,771
|
|
|
$
|
1,044,143
|
|
|
|
Crude Oil (MBbl)
|
|
Natural Gas (MMcf)
|
|
Total (MBoe)
|
|||
Net proved reserves at December 31, 2014
|
|
17,067
|
|
|
204,256
|
|
|
51,109
|
|
Revisions of previous estimates
1
|
|
(197
|
)
|
|
(17,043
|
)
|
|
(3,037
|
)
|
Purchases of minerals in place
2
|
|
8
|
|
|
367
|
|
|
69
|
|
Extensions, discoveries and other additions
3
|
|
2,529
|
|
|
57,484
|
|
|
12,110
|
|
Production
|
|
(3,565
|
)
|
|
(41,389
|
)
|
|
(10,463
|
)
|
Net proved reserves at December 31, 2015
|
|
15,842
|
|
|
203,675
|
|
|
49,788
|
|
Revisions of previous estimates
1
|
|
3,007
|
|
|
29,024
|
|
|
7,844
|
|
Purchases of minerals in place
4
|
|
1,322
|
|
|
5,683
|
|
|
2,269
|
|
Extensions, discoveries and other additions
5
|
|
1,877
|
|
|
79,455
|
|
|
15,120
|
|
Production
|
|
(3,680
|
)
|
|
(47,498
|
)
|
|
(11,596
|
)
|
Net proved reserves at December 31, 2016
|
|
18,368
|
|
|
270,339
|
|
|
63,425
|
|
Revisions of previous estimates
1
|
|
(1,234
|
)
|
|
21,067
|
|
|
2,277
|
|
Purchases of minerals in place
6
|
|
2,267
|
|
|
30,250
|
|
|
7,309
|
|
Extensions, discoveries and other additions
7
|
|
2,050
|
|
|
38,397
|
|
|
8,449
|
|
Production
|
|
(3,552
|
)
|
|
(59,779
|
)
|
|
(13,515
|
)
|
Net proved reserves at December 31, 2017
|
|
17,899
|
|
|
300,274
|
|
|
67,945
|
|
Net Proved Developed Reserves
8
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
15,497
|
|
|
174,555
|
|
|
44,590
|
|
December 31, 2016
|
|
18,150
|
|
|
223,057
|
|
|
55,327
|
|
December 31, 2017
|
|
17,891
|
|
|
233,017
|
|
|
56,727
|
|
Net Proved Undeveloped Reserves
9
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
345
|
|
|
29,120
|
|
|
5,198
|
|
December 31, 2016
|
|
218
|
|
|
47,282
|
|
|
8,098
|
|
December 31, 2017
|
|
8
|
|
|
67,257
|
|
|
11,218
|
|
1
|
Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. The most notable technical revisions are related to well performance in certain Haynesville/Bossier wells.
|
2
|
Includes the acquisition of mineral-and-royalty reserves primarily located throughout Texas, including in the Eagle Ford Shale and Wolfcamp plays and working interest reserves, the substantial majority of which is located in the Haynesville/Bossier play in San Augustine County, Texas.
|
3
|
Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Eagle Ford Shale, Wilcox, Granite Wash, and Fayetteville plays.
|
4
|
Includes the acquisition of mineral-and-royalty reserves primarily in the Marcellus and Wolfcamp plays.
|
5
|
Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Wilcox, Eagle Ford, and Fayetteville plays.
|
6
|
Includes the acquisition of mineral-and-royalty reserves primarily in East Texas and the Permian and Williston basins.
|
7
|
Includes extensions and additions related to drilling activities within multiple basins.
|
8
|
Proved developed reserves of
61
MBoe,
74
MBoe, and
84
MBoe as of December 31, 2017, 2016, and 2015, respectively, were attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries.
|
9
|
As of December 31, 2017, 2016, and 2015,
no
proved undeveloped reserves were attributable to noncontrolling interests.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(in thousands)
|
||||||||||
Future cash inflows
|
|
$
|
1,643,582
|
|
|
$
|
1,267,179
|
|
|
$
|
1,211,290
|
|
Future production costs
|
|
(211,064
|
)
|
|
(193,749
|
)
|
|
(205,861
|
)
|
|||
Future development costs
|
|
(70,111
|
)
|
|
(36,509
|
)
|
|
(84,746
|
)
|
|||
Future income tax expense
|
|
(2,655
|
)
|
|
(3,516
|
)
|
|
—
|
|
|||
Future net cash flows (undiscounted)
|
|
1,359,752
|
|
|
1,033,405
|
|
|
920,683
|
|
|||
Annual discount 10% for estimated timing
|
|
(497,103
|
)
|
|
(430,390
|
)
|
|
(365,711
|
)
|
|||
Total
1
|
|
$
|
862,649
|
|
|
$
|
603,015
|
|
|
$
|
554,972
|
|
1
|
Includes standardized measure of discounted future net cash flows of approximately
$0.5 million
,
$0.6 million
, and
$0.7 million
for December 31, 2017, 2016, and 2015, attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(in thousands)
|
||||||||||
Standardized measure, beginning of year
|
|
$
|
603,015
|
|
|
$
|
554,972
|
|
|
$
|
1,143,094
|
|
Sales, net of production costs
|
|
(295,941
|
)
|
|
(210,354
|
)
|
|
(222,206
|
)
|
|||
Net changes in prices and production costs related to future production
|
|
169,608
|
|
|
(81,456
|
)
|
|
(621,065
|
)
|
|||
Extensions, discoveries and improved recovery, net of future production and development costs
|
|
113,199
|
|
|
86,606
|
|
|
165,020
|
|
|||
Previously estimated development costs incurred during the period
|
|
11,118
|
|
|
28,909
|
|
|
7,084
|
|
|||
Revisions of estimated future development costs
|
|
2,653
|
|
|
—
|
|
|
669
|
|
|||
Revisions of previous quantity estimates, net of related costs
|
|
86,228
|
|
|
147,507
|
|
|
(67,911
|
)
|
|||
Accretion of discount
|
|
60,512
|
|
|
55,662
|
|
|
114,309
|
|
|||
Purchases of reserves in place, less related costs
|
|
107,891
|
|
|
34,751
|
|
|
584
|
|
|||
Other
|
|
4,366
|
|
|
(13,582
|
)
|
|
35,394
|
|
|||
Net increase (decrease) in standardized measures
|
|
259,634
|
|
|
48,043
|
|
|
(588,122
|
)
|
|||
Standardized measure, end of year
|
|
$
|
862,649
|
|
|
$
|
603,015
|
|
|
$
|
554,972
|
|
|
|
First
Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
2
|
||||||||
|
|
(In thousands, except for per unit data)
|
||||||||||||||
2017
|
|
|
|
|
|
|
|
|
||||||||
Total revenue
|
|
$
|
124,582
|
|
|
$
|
120,524
|
|
|
$
|
89,111
|
|
|
$
|
95,442
|
|
Income (loss) from operations
|
|
65,015
|
|
|
57,840
|
|
|
26,216
|
|
|
23,013
|
|
||||
Net income (loss)
|
|
61,583
|
|
|
54,174
|
|
|
22,034
|
|
|
19,362
|
|
||||
Net income (loss) attributable to the general partner and common and subordinated units
|
|
60,460
|
|
|
53,518
|
|
|
21,388
|
|
|
16,779
|
|
||||
Net income (loss) attributable to common and subordinated units per unit (basic)
1
|
|
|
|
|
|
|
|
|
|
|||||||
Per common unit (basic)
|
|
0.37
|
|
|
0.33
|
|
|
0.16
|
|
|
0.15
|
|
||||
Per subordinated unit (basic)
|
|
0.26
|
|
|
0.22
|
|
|
0.05
|
|
|
0.03
|
|
||||
Net income (loss) attributable to common and subordinated units per unit (diluted)
1
|
|
|
|
|
|
|
|
|
||||||||
Per common unit (diluted)
|
|
0.37
|
|
|
0.33
|
|
|
0.16
|
|
|
0.15
|
|
||||
Per subordinated unit (diluted)
|
|
0.26
|
|
|
0.22
|
|
|
0.05
|
|
|
0.03
|
|
||||
Cash distributions declared and paid per limited partner unit
|
|
|
|
|
|
|
|
|
|
|
||||||
Per common unit
|
|
$
|
0.2875
|
|
|
$
|
0.2875
|
|
|
$
|
0.3125
|
|
|
$
|
0.3125
|
|
Per subordinated unit
|
|
$
|
0.1838
|
|
|
$
|
0.1838
|
|
|
$
|
0.2088
|
|
|
$
|
0.2088
|
|
Total assets
|
|
$
|
1,199,722
|
|
|
$
|
1,250,086
|
|
|
$
|
1,246,070
|
|
|
$
|
1,576,451
|
|
Long-term debt
|
|
388,000
|
|
|
393,000
|
|
|
362,000
|
|
|
388,000
|
|
||||
Total mezzanine equity
|
|
34,145
|
|
|
27,085
|
|
|
27,092
|
|
|
322,422
|
|
||||
2016
|
|
|
|
|
|
|
|
|
||||||||
Total revenue
|
|
$
|
64,381
|
|
|
$
|
40,569
|
|
|
$
|
99,171
|
|
|
$
|
56,712
|
|
Net income (loss)
|
|
11,610
|
|
|
(19,478
|
)
|
|
39,316
|
|
|
(3,979
|
)
|
||||
Income (loss) from operations
|
|
10,749
|
|
|
(20,810
|
)
|
|
37,535
|
|
|
(7,286
|
)
|
||||
Net income (loss) attributable to the general partner and common and subordinated units
|
|
8,943
|
|
|
(22,111
|
)
|
|
36,219
|
|
|
(8,614
|
)
|
||||
Net income (loss) attributable to common and subordinated units per unit (basic)
1
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Per common unit (basic)
|
|
0.09
|
|
|
(0.08
|
)
|
|
0.24
|
|
|
0.01
|
|
||||
Per subordinated unit (basic)
|
|
0.01
|
|
|
(0.15
|
)
|
|
0.14
|
|
|
(0.11
|
)
|
||||
Net income (loss) attributable to common and subordinated units per unit (diluted)
1
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Per common unit (diluted)
|
|
0.09
|
|
|
(0.08
|
)
|
|
0.24
|
|
|
0.01
|
|
||||
Per subordinated unit (diluted)
|
|
0.01
|
|
|
(0.15
|
)
|
|
0.14
|
|
|
(0.11
|
)
|
||||
Cash distributions declared per limited partner unit
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Per common unit
|
|
$
|
0.2625
|
|
|
$
|
0.2625
|
|
|
$
|
0.2875
|
|
|
$
|
0.2875
|
|
Per subordinated unit
|
|
$
|
0.1838
|
|
|
$
|
0.1838
|
|
|
$
|
0.1838
|
|
|
$
|
0.1838
|
|
Total assets
|
|
1,045,843
|
|
|
1,126,830
|
|
|
1,137,232
|
|
|
1,128,827
|
|
||||
Long-term debt
|
|
116,000
|
|
|
285,000
|
|
|
299,000
|
|
|
316,000
|
|
||||
Total mezzanine equity
|
|
54,001
|
|
|
54,001
|
|
|
54,015
|
|
|
54,015
|
|
||||
|
|
|
|
|
|
|
|
|
(m)
|
the Preferred Stock and the Series B Preferred Stock.
|
|
|
|
|
|
BLACK STONE MINERALS COMPANY, L.P.,
as Borrower
|
||
|
|
|
|
|
By:
|
|
BSMC GP, L.L.C.,
its General Partner
|
|
|
|
|
|
By:
|
|
Black Stone Minerals, L.P.,
its Sole Member
|
|
|
|
|
|
By:
|
|
Black Stone Minerals GP, L.L.C.,
its General Partner
|
|
|
|
|
|
By:
|
|
/s/ Jeffrey P. Wood
|
|
|
|
Jeffrey P. Wood
|
|
|
|
Senior Vice President and
Chief Financial Officer
|
|
|
||
|
BLACK STONE MINERALS, L.P.
, as Parent MLP
|
||
|
|
|
|
|
By:
|
|
Black Stone Minerals GP, L.L.C.,
its General Partner
|
|
|
|
|
|
By:
|
|
/s/ Jeffrey P. Wood
|
|
|
|
Jeffrey P. Wood
|
|
|
|
Senior Vice President
and Chief Financial Officer
|
|
|
|
|
|
WELLS FARGO BANK, NATIONAL ASSOCIATION,
|
||
|
as Administrative Agent, Issuing Bank and a Lender
|
||
|
|
|
|
|
By:
|
|
/s/ Lila Jordan
|
|
Name:
|
|
Lila Jordan
|
|
Title:
|
|
Managing Director
|
|
|
|
|
|
BANK OF AMERICA, N.A.,
as a Lender
|
||
|
|
|
|
|
By:
|
|
/s/ Alia Qaddumi
|
|
Name:
|
|
Alia Qaddumi
|
|
Title:
|
|
Director
|
|
|
|
|
|
COMPASS BANK,
as a Lender
|
||
|
|
|
|
|
By:
|
|
/s/ Gabriela Azcarate
|
|
Name:
|
|
Gabriela Azcarate
|
|
Title:
|
|
Vice President
|
|
|
|
|
|
JPMORGAN CHASE BANK N.A.,
as a Lender
|
||
|
|
|
|
|
By:
|
|
/s/ Theresa M. Benson
|
|
Name:
|
|
Theresa M. Benson
|
|
Title:
|
|
Authorized Officer
|
|
|
|
|
|
NATIXIS, NEW YORK BRANCH,
as a Lender
|
||
|
|
|
|
|
By:
|
|
/s/ Brice Le Foyer
|
|
Name:
|
|
Brice Le Foyer
|
|
Title:
|
|
Director
|
|
|
|
|
|
By:
|
|
/s/ Ajay Prakash
|
|
Name:
|
|
Ajay Prakash
|
|
Title:
|
|
Vice President
|
|
|
|
|
|
ZB, N.A. DBA AMEGY BANK,
as a Lender
|
||
|
|
|
|
|
By:
|
|
/s/ Sam Trail
|
|
Name:
|
|
Sam Trail
|
|
Title:
|
|
Senior Vice President
|
|
|
|
|
|
THE BANK OF NOVA SCOTIA, HOUSTON BRANCH,
as a Lender
|
||
|
|
|
|
|
By:
|
|
/s/ Alan Dawson
|
|
Name:
|
|
Alan Dawson
|
|
Title:
|
|
Director
|
|
|
|
|
|
IBERIABANK,
|
||
|
as a Lender
|
||
|
|
|
|
|
By:
|
|
/s/ Blake Norris
|
|
Name:
|
|
Blake Norris
|
|
Title:
|
|
Vice President
|
|
|
|
|
|
ABN AMRO CAPITAL USA LLC,
|
||
|
as a Lender
|
||
|
|
|
|
|
By:
|
|
/s/ Darrell Holley
|
|
Name:
|
|
Darrell Holley
|
|
Title:
|
|
Managing Director
|
|
|
|
|
|
By:
|
|
/s/ Michaela Braun
|
|
Name:
|
|
Michaela Braun
|
|
Title:
|
|
Director
|
|
|
|
|
|
KEYBANK, NATIONAL ASSOCIATION,
|
||
|
as a Lender
|
||
|
|
|
|
|
By:
|
|
/s/ George E. McKean
|
|
Name:
|
|
George E. McKean
|
|
Title:
|
|
Senior Vice President
|
|
|
|
|
|
TEXAS CAPITAL BANK, N.A.,
|
||
|
as a Lender
|
||
|
|
|
|
|
By:
|
|
/s/ James E. Hibbert, Jr.
|
|
Name:
|
|
James E. Hibbert, Jr.
|
|
Title:
|
|
Assistant Vice President
|
|
|
|
|
|
BOKF, N.A. DBA BANK OF TEXAS.,
|
||
|
as a Lender
|
||
|
|
|
|
|
By:
|
|
/s/ Marisol Salazar
|
|
Name:
|
|
Marisol Salazar
|
|
Title:
|
|
SVP
|
|
|
|
|
|
BLACK STONE ENERGY COMPANY, L.L.C.
|
||
|
|
|
|
|
By:
|
|
Black Stone Minerals Company, L.P.,
|
|
|
|
its Sole Member
|
|
|
|
|
|
By:
|
|
BSMC GP, L.L.C.,
|
|
|
|
its General Partner
|
|
|
|
|
|
By:
|
|
Black Stone Minerals, L.P.,
|
|
|
|
its Sole Member
|
|
|
|
|
|
By:
|
|
Black Stone Minerals GP, L.L.C.,
|
|
|
|
its General Partner
|
|
|
|
|
|
By:
|
|
/s/ Jeffrey P. Wood
|
|
|
|
Jeffrey P. Wood
|
|
|
|
Senior Vice President and Chief Financial Officer
|
|
|
||
|
BLACK STONE NATURAL RESOURCES, L.L.C.
|
||
|
|
|
|
|
By:
|
|
Black Stone Minerals Company, L.P.,
|
|
|
|
its Sole Member
|
|
|
|
|
|
By:
|
|
BSMC GP, L.L.C.,
|
|
|
|
its General Partner
|
|
|
|
|
|
By:
|
|
Black Stone Minerals, L.P.,
|
|
|
|
its Sole Member
|
|
|
|
|
|
By:
|
|
Black Stone Minerals GP, L.L.C.,
|
|
|
|
its General Partner
|
|
|
|
|
|
By:
|
|
/s/ Jeffrey P. Wood
|
|
|
|
Jeffrey P. Wood
|
|
|
|
Senior Vice President and Chief Financial Officer
|
|
|
|
|
|
TLW INVESTMENTS, L.L.C.
|
||
|
|
|
|
|
By:
|
|
Black Stone Energy Company, L.L.C.,
|
|
|
|
its Manager
|
|
|
|
|
|
By:
|
|
Black Stone Minerals Company, L.P.,
|
|
|
|
its Sole Member
|
|
|
|
|
|
By:
|
|
BSMC GP, L.L.C.,
|
|
|
|
its General Partner
|
|
|
|
|
|
By:
|
|
Black Stone Minerals, L.P.,
|
|
|
|
its Sole Member
|
|
|
|
|
|
By:
|
|
Black Stone Minerals GP, L.L.C.,
|
|
|
|
its General Partner
|
|
|
|
|
|
By:
|
|
/s/ Jeffrey P. Wood
|
|
|
|
Jeffrey P. Wood
|
|
|
|
Senior Vice President and Chief Financial Officer
|
|
|
||
|
BSAP II GP, L.L.C.
|
||
|
|
|
|
|
By:
|
|
Black Stone Minerals Company, L.P.,
|
|
|
|
its Sole Member
|
|
|
|
|
|
By:
|
|
BSMC GP, L.L.C.,
|
|
|
|
its General Partner
|
|
|
|
|
|
By:
|
|
Black Stone Minerals, L.P.,
|
|
|
|
its Sole Member
|
|
|
|
|
|
By:
|
|
Black Stone Minerals GP, L.L.C.,
|
|
|
|
its General Partner
|
|
|
|
|
|
By:
|
|
/s/ Jeffrey P. Wood
|
|
|
|
Jeffrey P. Wood
|
|
|
|
Senior Vice President and Chief Financial Officer
|
|
|
|
|
|
BLACK STONE MINERALS, L.P.
|
||
|
|
|
|
|
By:
|
|
Black Stone Minerals GP, L.L.C.,
|
|
|
|
its General Partner
|
|
|
|
|
|
By:
|
|
/s/ Jeffrey P. Wood
|
|
|
|
Jeffrey P. Wood
|
|
|
|
Senior Vice President and Chief Financial Officer
|
|
|
||
|
BSMC GP, L.L.C.
|
||
|
|
|
|
|
By:
|
|
Black Stone Minerals, L.P.,
|
|
|
|
its Sole Member
|
|
|
|
|
|
By:
|
|
Black Stone Minerals GP, L.L.C.,
|
|
|
|
its General Partner
|
|
|
|
|
|
By:
|
|
/s/ Jeffrey P. Wood
|
|
|
|
Jeffrey P. Wood
|
|
|
|
Senior Vice President and Chief Financial Officer
|
Target STI Award:
|
$[●] (the “
Target Amount
”)
|
Performance Period:
|
January 1, 2018 through December 31, 2018
|
|
Below Threshold
|
Threshold
|
Target
|
Maximum
|
Partnership’s EBITDAX for the Performance Period
|
˂ $[●]
|
$[●]
|
$[●]
|
≥$[●]
|
Percentage of Target Amount that is Earned*
|
0%
|
50%
|
100%
|
200%
|
Title:
|
Senior Vice President, General Counsel, and Secretary
|
|
|
|
Entity
|
|
Jurisdiction of Organization
|
Black Stone Energy Company, L.L.C.
|
|
Texas
|
Black Stone Minerals Company, L.P.
|
|
Delaware
|
Black Stone Minerals GP, L.L.C.
|
|
Delaware
|
Black Stone Natural Resources, L.L.C.
|
|
Delaware
|
Black Stone Natural Resources Management Company
|
|
Texas
|
BSAP II GP, L.L.C.
|
|
Delaware
|
BSMC GP, L.L.C.
|
|
Delaware
|
O’Connell Holdings, L.L.C.
|
|
Delaware
|
O’Connell Partners, L.P.
|
|
Delaware
|
TLW Investments, L.L.C.
|
|
Oklahoma
|
|
(1)
|
Registration Statement (Form S-8 No. 333-203909) pertaining to the Long-Term Incentive Plan of Black Stone Minerals, L.P.,
|
|
(2)
|
Registration Statement (Form S-3 No. 333-211426) of Black Stone Minerals, L.P., and
|
|
(3)
|
Registration Statement (Form S-3 No. 333-215857) of Black Stone Minerals, L.P.;
|
|
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
||
|
|
|
|
|
|
By:
|
/s/ J. Carter Henson, Jr.
|
|
|
|
|
J. Carter Henson, Jr., P.E.
|
|
|
|
|
Senior Vice President
|
|
|
|
|
|
|
|
|
|
Houston, Texas
|
|
|
|
|
February 28, 2018
|
|
|
1.
|
I have reviewed this report on Form 10-K of Black Stone Minerals, L.P. (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 officers 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 controls 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 officers 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.
|
Date:
|
February 28, 2018
|
|
/s/ Thomas L. Carter, Jr.
|
|
|
|
|
Thomas L. Carter, Jr.
|
|
|
|
|
President, Chief Executive Officer and Chairman
|
|
|
|
|
Black Stone Minerals GP, L.L.C.,
the general partner of Black Stone Minerals, L.P.
|
|
1.
|
I have reviewed this report on Form 10-K of Black Stone Minerals, L.P. (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 officers 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 controls 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
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d.
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Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
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5.
|
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
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|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
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Date:
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February 28, 2018
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/s/ Jeff Wood
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Jeff Wood
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Senior Vice President and Chief Financial Officer
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Black Stone Minerals GP, L.L.C.,
the general partner of Black Stone Minerals, L.P.
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|
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(1)
|
the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
|
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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Date:
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February 28, 2018
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/s/ Thomas L. Carter, Jr.
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Thomas L. Carter, Jr.
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President, Chief Executive Officer and Chairman
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Black Stone Minerals GP, L.L.C.,
the general partner of Black Stone Minerals, L.P.
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|
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Date:
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February 28, 2018
|
|
/s/ Jeff Wood
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Jeff Wood
|
|
|
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Senior Vice President and Chief Financial Officer
|
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Black Stone Minerals GP, L.L.C.,
the general partner of Black Stone Minerals, L.P.
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Net Reserves
|
|
Future Net Revenue (M$)
|
||||
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|
Oil
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|
Gas
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|
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Present Worth
|
Category
|
|
(MBBL)
|
|
(MMCF)
|
|
Total
|
|
at 10%
|
Proved Developed Producing
|
|
17,779.8
|
|
229,339.8
|
|
1,206,542.4
|
|
757,843.0
|
Proved Developed Non-Producing
|
|
111.4
|
|
3,676.7
|
|
18,846.9
|
|
13,131.1
|
Proved Undeveloped
|
|
7.9
|
|
67,257.5
|
|
137,017.2
|
|
93,436.2
|
Total Proved
|
|
17,899.2
|
|
300,274.0
|
|
1,362,406.6
|
|
864,410.3
|
|
|
|
Sincerely,
|
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||
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NETHERLAND, SEWELL & ASSOCIATES, INC.
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|
|||
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Texas Registered Engineering Firm F-2699
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/s/ C.H. (Scott) Rees III
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||
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By:
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C.H. (Scott) Rees III, P.E.
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|
||
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Chairman and Chief Executive Officer
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|
||
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/s/ J. Carter Henson, Jr.
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||
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By:
|
|
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J. Carter Henson, Jr., P.E. 73964
|
|
||
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Senior Vice President
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|
||
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|
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Date Signed: January 24, 2018
|
|
(i)
|
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
|
(ii)
|
Same environment of deposition;
|
(iii)
|
Similar geological structure; and
|
(iv)
|
Same drive mechanism.
|
(i)
|
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
|
(ii)
|
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
|
(i)
|
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
|
(ii)
|
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
|
(iii)
|
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
|
(iv)
|
Provide improved recovery systems.
|
(i)
|
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
|
(ii)
|
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
|
(iii)
|
Dry hole contributions and bottom hole contributions.
|
(iv)
|
Costs of drilling and equipping exploratory wells.
|
(v)
|
Costs of drilling exploratory-type stratigraphic test wells.
|
(i)
|
Oil and gas producing activities include:
|
(A)
|
The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
|
(B)
|
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
|
(C)
|
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
|
(1)
|
Lifting the oil and gas to the surface; and
|
(2)
|
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
|
(D)
|
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
|
a.
|
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
|
b.
|
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
|
(ii)
|
Oil and gas producing activities do not include:
|
(A)
|
Transporting, refining, or marketing oil and gas;
|
(B)
|
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
|
(C)
|
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
|
(D)
|
Production of geothermal steam.
|
(i)
|
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be
|
(ii)
|
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
|
(iii)
|
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
|
(iv)
|
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
|
(v)
|
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
|
(vi)
|
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
|
(i)
|
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
|
(ii)
|
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
|
(iii)
|
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
|
(iv)
|
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
|
(i)
|
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
|
(A)
|
Costs of labor to operate the wells and related equipment and facilities.
|
(B)
|
Repairs and maintenance.
|
(C)
|
Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
|
(D)
|
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
|
(E)
|
Severance taxes.
|
(ii)
|
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
|
(i)
|
The area of the reservoir considered as proved includes:
|
(A)
|
The area identified by drilling and limited by fluid contacts, if any, and
|
(B)
|
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
|
(ii)
|
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
|
(iii)
|
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
|
(iv)
|
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
|
(A)
|
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
|
(B)
|
The project has been approved for development by all necessary parties and entities, including governmental entities.
|
(v)
|
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
(ii)
|
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
|
•
|
The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
|
•
|
The company's historical record at completing development of comparable long-term projects;
|
•
|
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
|
•
|
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
|
•
|
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).
|
(iii)
|
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
|