ITEMS 1 AND 2. BUSINESS AND PROPERTIES
General
We are one of the largest owners of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests. We maximize value through marketing our mineral assets for lease, creatively structuring terms on those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working-interest basis in low-risk development-drilling opportunities on our interests. Our primary business objective is to grow our reserves, production, and cash generated from operations over the long term, while paying, to the extent practicable, a growing quarterly distribution to our unitholders.
We own mineral interests in approximately 15.5 million acres, with an average 45.7% ownership interest in that acreage. We also own nonparticipating royalty interests in 1.5 million acres and overriding royalty interests in 1.5 million acres. These non-cost-bearing interests, which we refer to collectively as our “mineral and royalty interests,” include ownership in approximately 50,000 producing wells. Our mineral and royalty interests are located in 41 states and in 64 onshore basins in the continental United States. Many of these interests are in active resource plays, including the Bakken/Three Forks in the Williston Basin, the Eagle Ford Shale in South Texas, the Wolfcamp/Spraberry/Bone Spring in the Permian Basin, the Niobrara/Codell Shales in the DJ basin, the Haynesville/Bossier Shales in East Texas/Western Louisiana, and the Fayetteville Shale in the Arkoma Basin, as well as emerging plays such as the Lower Wilcox play in East Texas and the Canyon Lime play in the Texas Panhandle. The combination of the breadth of our asset base and the long-lived, non-cost-bearing nature of our mineral and royalty interests exposes us to potential additional production and reserves from new and existing plays without investing additional capital.
We are a publicly traded Delaware limited partnership formed on September 16, 2014. On May 6, 2015, we completed our initial public offering of 22,500,000 common units representing limited partner interests at a price to the public of $19.00 per common unit. Our common units trade on the New York Stock Exchange under the symbol "BSM."
BSM files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to these reports with the U.S. Securities and Exchange Commission (“SEC”). Through our website, http://www.blackstoneminerals.com, we make available electronic copies of the documents we file or furnish to the SEC. Access to these electronic filings is available free of charge as soon as reasonably practicable after filing or furnishing them to the SEC.
Our Assets
As of December 31, 2016, our total estimated proved oil and natural gas reserves were 63,425 MBoe based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent third-party petroleum engineering firm. Of the reserves as of December 31, 2016, approximately 87.2% were proved developed reserves (approximately 78.2% proved developed producing and 9.0% proved developed non-producing) and approximately 12.8% were proved undeveloped reserves. At December 31, 2016, our estimated proved reserves were 29.0% oil and 71.0% natural gas.
The locations of our oil and natural gas properties are presented on the following map. Additional information related to these properties follows this map.
Mineral and Royalty Interests
Mineral interests are real-property interests that are typically perpetual and grant ownership of the oil and natural gas under a tract of land and the rights to explore for, drill for, and produce oil and natural gas on that land or to lease those exploration and development rights to a third party. When those rights are leased, usually for a three-year term, we typically receive an upfront cash payment, known as lease bonus, and we retain a mineral royalty, which entitles us to a cost-free percentage (usually ranging from 20% to 25%) of production or revenue from production. A lessee can extend the lease beyond the initial lease term with continuous drilling, production, or other operating activities. When production or drilling ceases, the lease terminates, allowing us to lease the exploration and development rights to another party. Mineral interests generate the substantial majority of our revenue and are also the assets that we have the most influence over.
In addition to mineral interests, we also own other types of non-cost-bearing royalty interests, which include:
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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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Working-Interest Participation Program
We own working interests related to our mineral interests in various plays across our asset base. Many of these working interests were acquired through working-interest participation rights, which we often include in the terms of our leases. This participation right complements our core mineral-and-royalty-interest business because it allows us to realize additional value from our minerals. Under the terms of the relevant leases, we are typically granted a unit-by-unit or a well-by-well option to participate on a non-operated, working-interest basis in drilling opportunities on our mineral acreage. This right to participate in a unit or well is exercisable at our sole discretion. We generally only exercise this option when the results from prior drilling and production activities have substantially reduced the economic risk associated with development drilling and where we
believe the probability of achieving attractive economic returns is high. A small portion of our working interests, unrelated to our mineral and royalty assets, were acquired because of the attractive working-interest investment opportunities on those properties. The majority of these assets are focused in the Anadarko Basin, and to a lesser extent, in the Permian and Powder River Basins.
We collectively refer to these working interests as our “working-interest participation program.” When we participate in non-operated working-interest opportunities, we are required to pay our portion of the costs associated with drilling and operating these wells. Our 2017 drilling capital expenditure budget associated with our working-interest participation program is expected to range between $50 and $60 million. Approximately 90% of our 2017 drilling capital budget will be spent in the Haynesville/Bossier play with the remainder spent in various plays including the Bakken/Three Forks and Wolfcamp plays. As of December 31, 2016, we owned non-operated working interests in over 8,500 gross (328 net) wells.
Working interest production represented 35.0% of our total production volumes during the year ended December 31, 2016.
Our Properties
Material Basins and Producing Regions
We may own more than one type of interest in the same tract of land. For example, where we have acquired working interests through our working-interest participation program in a given tract, our working-interest acreage in that tract will relate to the same acres as our mineral-interest acreage in that tract. Consequently, some of the acreage shown for one type of interest above may also be included in the acreage shown for another type of interest. Because of our working-interest participation program, overlap between working-interest acreage and mineral-and-royalty-interest acreage is significant, while overlap between the different types of mineral and royalty interests is not significant. The following table describes our mineral and royalty interests and working interests:
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Acreage as of December 31, 2016
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Average Daily
Production (Boe/d)
For the Year Ended
December 31, 2016
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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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5,446,455
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162,199
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18,846
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49,170
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6,203
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5,053
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Western Gulf (onshore)
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1,597,765
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213,111
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98,752
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116,134
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17,394
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6,191
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Williston Basin
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1,323,172
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62,133
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31,884
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54,734
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7,741
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4,061
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Palo Duro Basin
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1,016,847
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22,791
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1,120
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—
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—
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24
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Permian Basin
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1,016,197
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587,167
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177,275
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8,113
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4,731
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1,441
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Anadarko Basin
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550,740
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13,723
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180,157
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31,313
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21,294
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1,909
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Appalachian Basin
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490,274
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416
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14,836
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—
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—
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874
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East Texas Basin
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456,110
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44,429
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30,640
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151,811
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51,589
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6,906
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Arkoma Basin
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338,767
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9,087
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37,957
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9,045
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2,333
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1,614
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Bend Arch-Fort Worth Basin
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144,246
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55,205
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40,249
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53,606
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13,585
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427
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Southwestern Wyoming
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22,338
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—
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75,577
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15,336
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2,477
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454
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Other
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3,113,014
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310,992
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798,542
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39,408
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8,924
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2,729
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Total
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15,515,925
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1,481,253
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1,505,835
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528,670
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136,271
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31,683
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1
Excludes acreage for which we have incomplete seller records.
2
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.”
The following is an overview of the U.S. basins and regions we consider most material to our current and future business.
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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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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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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
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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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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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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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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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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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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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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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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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Interests by USGS Petroleum Province
The following tables present information about our mineral-and-royalty-interest and non-operated working-interest acreage, production, and well count by USGS petroleum province.
Mineral Interests
The following table sets forth information about our mineral interests:
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Average Daily Production (Boe/d)
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As of December 31, 2016
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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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2016
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2015
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2014
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Louisiana-Mississippi Salt Basins
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5,446,455
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53.4
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%
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9.6
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%
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3,415
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3,384
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4,061
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Western Gulf (onshore)
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1,597,765
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55.0
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%
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34.7
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%
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4,526
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5,021
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4,099
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Williston Basin
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1,323,172
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14.8
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%
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35.4
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%
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2,534
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2,430
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1,989
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Palo Duro Basin
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1,016,847
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46.5
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%
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7.2
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%
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24
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23
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16
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Permian Basin
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1,016,197
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14.0
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%
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66.6
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%
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1,035
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585
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566
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Black Warrior Basin
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592,968
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54.6
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%
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2.3
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%
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—
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39
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41
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Eastern Great Basin
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567,749
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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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Anadarko Basin
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550,740
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32.7
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%
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59.6
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%
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673
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959
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790
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Appalachian Basin
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490,274
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39.8
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%
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22.1
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%
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163
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80
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89
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East Texas Basin
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456,110
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52.7
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%
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39.4
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%
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1,854
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884
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793
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Arkoma Basin
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338,767
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53.7
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%
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27.6
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%
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1,302
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1,458
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1,646
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Western Great Basin
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338,303
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90.5
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%
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–
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—
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—
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—
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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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North-Central Montana
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171,026
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13.7
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%
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27.8
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%
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9
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4
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7
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Atlantic Coastal Plain
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164,670
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12.8
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%
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28.8
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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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144,246
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20.5
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%
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33.3
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%
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—
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392
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252
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Cherokee Platform
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111,027
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13.8
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%
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32.4
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%
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34
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41
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46
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Florida Peninsula
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90,744
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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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53.1
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%
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8.0
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%
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3
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2
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1
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Powder River Basin
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67,055
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11.3
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%
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12.3
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%
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—
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56
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3
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Other
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771,067
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32.1
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%
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20.4
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%
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1,295
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301
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317
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Total
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15,515,925
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45.7
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%
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22.0
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%
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17,107
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15,659
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14,716
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1
The basins and regions shown in the table are consistent with USGS petroleum-province delineations.
2
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.
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.
NPRIs
The following table sets forth information about our NPRIs:
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Average Daily Production (Boe/d)
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As of December 31, 2016
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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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2016
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2015
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2014
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Permian Basin
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587,167
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2.1
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%
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47.5
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%
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19
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31
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11
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Western Gulf (onshore)
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213,111
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4.6
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%
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46.0
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%
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14
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10
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14
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Louisiana-Mississippi Salt Basins
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162,199
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4.9
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%
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48.3
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%
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1
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—
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<1
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North-Central Montana
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134,559
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3.0
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%
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9.3
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%
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—
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—
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—
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Marathon Thrust Belt
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117,442
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4.9
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%
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1.6
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%
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—
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—
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—
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Williston Basin
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62,133
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2.6
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%
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33.0
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%
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|
92
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|
|
106
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|
|
64
|
|
Bend Arch-Fort Worth Basin
|
|
55,205
|
|
|
4.1
|
%
|
|
12.1
|
%
|
|
1
|
|
|
—
|
|
|
3
|
|
East Texas Basin
|
|
44,429
|
|
|
2.7
|
%
|
|
80.3
|
%
|
|
179
|
|
|
381
|
|
|
2
|
|
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
|
%
|
|
18
|
|
|
8
|
|
|
2
|
|
Arkoma Basin
|
|
9,087
|
|
|
2.6
|
%
|
|
83.8
|
%
|
|
13
|
|
|
21
|
|
|
—
|
|
Cambridge Arch-Central Kansas Uplift
|
|
8,903
|
|
|
5.5
|
%
|
|
83.7
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Southwest Montana
|
|
4,367
|
|
|
6.2
|
%
|
|
7.3
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Cherokee Platform
|
|
2,635
|
|
|
4.6
|
%
|
|
33.4
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
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
|
|
1,549
|
|
|
5.7
|
%
|
|
22.6
|
%
|
|
180
|
|
|
185
|
|
|
151
|
|
Total
|
|
1,481,253
|
|
|
3.4
|
%
|
|
38.4
|
%
|
|
518
|
|
|
742
|
|
|
247
|
|
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.
ORRIs
The following table sets forth information about our ORRIs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (Boe/d)
|
|
|
As of December 31, 2016
|
|
For the Year Ended December 31,
|
USGS Petroleum Province
1
|
|
Acres
|
|
Average
Royalty
Interest
2
|
|
2016
|
|
2015
|
|
2014
|
North-Central Montana
|
|
457,897
|
|
|
2.5
|
%
|
|
13
|
|
|
35
|
|
|
36
|
|
Anadarko Basin
|
|
180,157
|
|
|
2.4
|
%
|
|
200
|
|
|
232
|
|
|
253
|
|
Permian Basin
|
|
177,275
|
|
|
0.8
|
%
|
|
64
|
|
|
72
|
|
|
60
|
|
Western Gulf (onshore)
|
|
98,752
|
|
|
1.7
|
%
|
|
157
|
|
|
262
|
|
|
166
|
|
Powder River Basin
|
|
85,078
|
|
|
3.6
|
%
|
|
45
|
|
|
98
|
|
|
50
|
|
Southwestern Wyoming
|
|
75,577
|
|
|
2.0
|
%
|
|
451
|
|
|
529
|
|
|
530
|
|
Uinta-Piceance Basin
|
|
63,503
|
|
|
1.6
|
%
|
|
24
|
|
|
37
|
|
|
32
|
|
Michigan Basin
|
|
56,512
|
|
|
1.0
|
%
|
|
18
|
|
|
21
|
|
|
21
|
|
Bend Arch-Fort Worth Basin
|
|
40,249
|
|
|
4.7
|
%
|
|
108
|
|
|
160
|
|
|
166
|
|
Arkoma Basin
|
|
37,957
|
|
|
3.0
|
%
|
|
23
|
|
|
29
|
|
|
23
|
|
San Juan Basin
|
|
36,239
|
|
|
1.1
|
%
|
|
6
|
|
|
3
|
|
|
3
|
|
Williston Basin
|
|
31,884
|
|
|
2.1
|
%
|
|
59
|
|
|
76
|
|
|
54
|
|
East Texas Basin
|
|
30,640
|
|
|
3.6
|
%
|
|
96
|
|
|
81
|
|
|
100
|
|
Northern Alaska
|
|
20,039
|
|
|
1.7
|
%
|
|
28
|
|
|
32
|
|
|
27
|
|
Paradox Basin
|
|
19,269
|
|
|
1.1
|
%
|
|
—
|
|
|
2
|
|
|
2
|
|
Louisiana-Mississippi Salt Basins
|
|
18,846
|
|
|
3.3
|
%
|
|
705
|
|
|
1,185
|
|
|
903
|
|
Denver Basin
|
|
15,880
|
|
|
3.2
|
%
|
|
117
|
|
|
83
|
|
|
91
|
|
Appalachian Basin
|
|
14,836
|
|
|
2.6
|
%
|
|
693
|
|
|
—
|
|
|
—
|
|
Wind River Basin
|
|
7,090
|
|
|
1.3
|
%
|
|
27
|
|
|
33
|
|
|
31
|
|
Cambridge Arch-Central Kansas Uplift
|
|
5,762
|
|
|
3.8
|
%
|
|
3
|
|
|
5
|
|
|
4
|
|
Other
|
|
32,393
|
|
|
1.6
|
%
|
|
156
|
|
|
911
|
|
|
884
|
|
Total
|
|
1,505,835
|
|
|
2.2
|
%
|
|
2,993
|
|
|
3,886
|
|
|
3,436
|
|
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.
Working Interests
The following table sets forth information about our non-operated working interests:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (Boe/d)
|
|
|
As of December 31, 2016
|
|
For the Year Ended December 31,
|
USGS Petroleum Province
1
|
|
Gross Acres
2
|
|
Net Acres
2
|
|
2016
|
|
2015
|
|
2014
|
East Texas Basin
|
|
151,811
|
|
|
51,589
|
|
|
4,776
|
|
|
2,341
|
|
|
1,564
|
|
Western Gulf (onshore)
|
|
116,134
|
|
|
17,394
|
|
|
1,494
|
|
|
1,234
|
|
|
786
|
|
Williston Basin
|
|
54,734
|
|
|
7,741
|
|
|
1,377
|
|
|
1,425
|
|
|
1,386
|
|
Bend Arch-Fort Worth Basin
|
|
53,606
|
|
|
13,585
|
|
|
118
|
|
|
108
|
|
|
129
|
|
Louisiana-Mississippi Salt Basins
|
|
49,170
|
|
|
6,203
|
|
|
932
|
|
|
1,007
|
|
|
2,077
|
|
Anadarko Basin
|
|
31,313
|
|
|
21,294
|
|
|
1,018
|
|
|
1,205
|
|
|
1,402
|
|
Southwestern Wyoming
|
|
15,336
|
|
|
2,477
|
|
|
11
|
|
|
1
|
|
|
6
|
|
Michigan Basin
|
|
13,287
|
|
|
1,330
|
|
|
6
|
|
|
6
|
|
|
6
|
|
Powder River Basin
|
|
13,016
|
|
|
3,389
|
|
|
103
|
|
|
169
|
|
|
121
|
|
Arkoma Basin
|
|
9,045
|
|
|
2,333
|
|
|
277
|
|
|
341
|
|
|
360
|
|
Permian Basin
|
|
8,113
|
|
|
4,731
|
|
|
323
|
|
|
214
|
|
|
204
|
|
Denver Basin
|
|
4,923
|
|
|
1,040
|
|
|
130
|
|
|
5
|
|
|
4
|
|
Paradox Basin
|
|
2,602
|
|
|
1,281
|
|
|
4
|
|
|
5
|
|
|
5
|
|
North-Central Montana
|
|
2,080
|
|
|
605
|
|
|
1
|
|
|
1
|
|
|
1
|
|
Uinta-Piceance Basin
|
|
1,005
|
|
|
482
|
|
|
68
|
|
|
—
|
|
|
—
|
|
San Juan Basin
|
|
960
|
|
|
334
|
|
|
15
|
|
|
11
|
|
|
9
|
|
Wind River Basin
|
|
440
|
|
|
43
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Southern Oklahoma
|
|
390
|
|
|
92
|
|
|
132
|
|
|
174
|
|
|
141
|
|
Cherokee Platform
|
|
328
|
|
|
137
|
|
|
1
|
|
|
5
|
|
|
9
|
|
Illinois Basin
|
|
200
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other
|
|
177
|
|
|
176
|
|
|
279
|
|
|
128
|
|
|
109
|
|
Total
|
|
528,670
|
|
|
136,272
|
|
|
11,065
|
|
|
8,380
|
|
|
8,319
|
|
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.
Wells
The following table sets forth information about our mineral-and-royalty-interest and working-interest wells as of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
Mineral and Royalty Interests
|
|
Working Interests
|
USGS Petroleum Province
1
|
|
Gross Well Count
2
|
|
USGS Petroleum Province
1
|
|
Gross Well Count
2
|
Permian Basin
|
|
21,887
|
|
|
Anadarko Basin
|
|
2,777
|
|
Anadarko Basin
|
|
3,672
|
|
|
Uinta-Piceance Basin
|
|
1,037
|
|
Williston Basin
|
|
3,034
|
|
|
Permian Basin
|
|
796
|
|
Louisiana-Mississippi Salt Basin
|
|
2,981
|
|
|
Arkoma Basin
|
|
727
|
|
East Texas Basin
|
|
2,925
|
|
|
Western Gulf (onshore)
|
|
595
|
|
Western Gulf (onshore)
|
|
2,887
|
|
|
East Texas Basin
|
|
567
|
|
Arkoma Basin
|
|
1,889
|
|
|
Williston Basin
|
|
541
|
|
Uinta-Piceance Basin
|
|
1,321
|
|
|
Louisiana-Mississippi Salt Basin
|
|
433
|
|
Bend Arch - Fort Worth Basin
|
|
1,173
|
|
|
Southern Oklahoma
|
|
408
|
|
Michigan Basin
|
|
971
|
|
|
Bend Arch - Fort Worth Basin
|
|
198
|
|
Appalachian Basin
|
|
826
|
|
|
Appalachian Basin
|
|
192
|
|
Southwestern Wyoming
|
|
684
|
|
|
Nemaha Uplift
|
|
105
|
|
Cherokee Platform
|
|
664
|
|
|
Powder River Basin
|
|
66
|
|
Denver Basin
|
|
558
|
|
|
Michigan Basin
|
|
62
|
|
North-Central Montana
|
|
532
|
|
|
Denver Basin
|
|
21
|
|
San Juan Basin
|
|
530
|
|
|
Cherokee Platform
|
|
14
|
|
Nemaha Uplift
|
|
502
|
|
|
North-Central Montana
|
|
10
|
|
San Joaquin Basin
|
|
465
|
|
|
Paradox Basin
|
|
8
|
|
Powder River Basin
|
|
399
|
|
|
Black Warrior Basin
|
|
5
|
|
Southern Oklahoma
|
|
376
|
|
|
Southwestern Wyoming
|
|
5
|
|
Other
|
|
1,666
|
|
|
Other
|
|
10
|
|
Total
|
|
49,942
|
|
|
Total
|
|
8,577
|
|
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 3,259 of the wells shown in each column above.
Material Resource Plays
We may own more than one type of interest in the same tract of land. For example, where we have acquired working interests through our working-interest participation program in a given tract, our working-interest acreage in that tract will relate to the same acres as our mineral-interest acreage in that tract. Consequently, some of the acreage shown for one type of interest above may also be included in the acreage shown for another type of interest. Because of our working-interest participation program, overlap between working-interest acreage and mineral-and-royalty-interest acreage is significant, while overlap between the different types of mineral and royalty interests is not significant. The following table presents information about our mineral-and-royalty-interest and working-interest acreage by the resource plays we consider most material to our current and future business. These plays accounted for 63% of our aggregate production for the year ended December 31, 2016.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acreage as of December 31, 2016
1
|
|
|
Mineral and Royalty Interests
|
|
Working Interests
|
Resource Play
2
|
|
Mineral Interests
|
|
NPRIs
|
|
ORRIs
|
|
Gross
|
|
Net
|
Bakken Shale
|
|
309,892
|
|
|
36,341
|
|
|
13,210
|
|
|
50,159
|
|
|
7,105
|
|
Three Forks
|
|
296,343
|
|
|
33,522
|
|
|
12,530
|
|
|
50,361
|
|
|
6,732
|
|
Haynesville Shale
|
|
283,401
|
|
|
7,255
|
|
|
14,719
|
|
|
183,337
|
|
|
53,546
|
|
Bossier Shale
|
|
252,458
|
|
|
1,816
|
|
|
8,642
|
|
|
170,716
|
|
|
52,130
|
|
Marcellus Shale
|
|
240,784
|
|
|
—
|
|
|
13,356
|
|
|
—
|
|
|
—
|
|
Canyon Lime
|
|
219,279
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Wolfcamp - Midland
|
|
187,152
|
|
|
97,860
|
|
|
125,817
|
|
|
160
|
|
|
4
|
|
Tuscaloosa Marine Shale
|
|
181,497
|
|
|
23,397
|
|
|
689
|
|
|
—
|
|
|
—
|
|
Granite Wash
|
|
102,786
|
|
|
5,031
|
|
|
86,556
|
|
|
4,840
|
|
|
1,254
|
|
Fayetteville Shale
|
|
71,089
|
|
|
3,918
|
|
|
11,708
|
|
|
—
|
|
|
—
|
|
Barnett Shale
|
|
62,732
|
|
|
4,164
|
|
|
36,155
|
|
|
13,417
|
|
|
7,747
|
|
Eagle Ford Shale
|
|
60,743
|
|
|
86,152
|
|
|
48,920
|
|
|
1,147
|
|
|
87
|
|
Wolfcamp - Delaware
|
|
44,520
|
|
|
28,061
|
|
|
4,643
|
|
|
2,642
|
|
|
971
|
|
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.
Interests by Resource Play
The following tables present information about our mineral-and-royalty-interest and non-operated working-interest acreage, and production by resource play. As with the acreage shown for the basins and regions above, we may own more than one type of interest in the same tract of land. Consequently, some of the acreage shown for one type of interest below may also be included in the acreage shown for another type of interest.
Mineral Interests
The following table sets forth information about our mineral interests:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (Boe/d)
|
|
|
As of December 31, 2016
|
|
For the Year Ended December 31,
|
Resource Play
1
|
|
Acres
|
|
Average
Ownership
Interest
2
|
|
Average
Ownership
Leased
3
|
|
2016
|
|
2015
|
|
2014
|
Bakken Shale
|
|
309,892
|
|
|
18.1
|
%
|
|
72.0
|
%
|
|
1,659
|
|
|
1,746
|
|
|
1,275
|
|
Three Forks
|
|
296,343
|
|
|
17.7
|
%
|
|
73.4
|
%
|
|
968
|
|
|
823
|
|
|
626
|
|
Haynesville Shale
|
|
283,401
|
|
|
63.6
|
%
|
|
66.7
|
%
|
|
3,727
|
|
|
2,728
|
|
|
3,152
|
|
Bossier Shale
|
|
252,458
|
|
|
69.0
|
%
|
|
64.6
|
%
|
|
330
|
|
|
351
|
|
|
548
|
|
Marcellus Shale
|
|
240,784
|
|
|
14.5
|
%
|
|
34.8
|
%
|
|
111
|
|
|
71
|
|
|
74
|
|
Canyon Lime
|
|
219,279
|
|
|
30.6
|
%
|
|
20.8
|
%
|
|
16
|
|
|
8
|
|
|
1
|
|
Wolfcamp - Midland
|
|
187,152
|
|
|
4.8
|
%
|
|
97.3
|
%
|
|
136
|
|
|
76
|
|
|
27
|
|
Tuscaloosa Marine Shale
|
|
181,497
|
|
|
60.8
|
%
|
|
68.0
|
%
|
|
52
|
|
|
46
|
|
|
6
|
|
Granite Wash
|
|
102,786
|
|
|
15.2
|
%
|
|
57.7
|
%
|
|
167
|
|
|
194
|
|
|
241
|
|
Fayetteville Shale
|
|
71,089
|
|
|
55.8
|
%
|
|
77.6
|
%
|
|
1,181
|
|
|
1,349
|
|
|
1,529
|
|
Barnett Shale
|
|
62,732
|
|
|
15.5
|
%
|
|
58.0
|
%
|
|
181
|
|
|
239
|
|
|
228
|
|
Eagle Ford Shale
|
|
60,743
|
|
|
15.5
|
%
|
|
83.8
|
%
|
|
2,095
|
|
|
2,355
|
|
|
1,595
|
|
Wolfcamp - Delaware
|
|
44,520
|
|
|
19.2
|
%
|
|
94.9
|
%
|
|
437
|
|
|
148
|
|
|
132
|
|
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.
NPRIs
The following table sets forth information about our NPRIs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (Boe/d)
|
|
|
As of December 31, 2016
|
|
For the Year Ended December 31,
|
Resource Play
1
|
|
Acres
|
|
Average
Royalty
Interest
2
|
|
Average
Percent
Leased
3
|
|
2016
|
|
2015
|
|
2014
|
Wolfcamp - Midland
|
|
97,860
|
|
|
0.7
|
%
|
|
75.3
|
%
|
|
11
|
|
|
22
|
|
|
5
|
|
Eagle Ford Shale
|
|
86,152
|
|
|
1.5
|
%
|
|
28.4
|
%
|
|
14
|
|
|
3
|
|
|
7
|
|
Bakken Shale
|
|
36,341
|
|
|
1.4
|
%
|
|
51.3
|
%
|
|
63
|
|
|
56
|
|
|
37
|
|
Three Forks
|
|
33,522
|
|
|
1.2
|
%
|
|
54.8%
|
|
|
36
|
|
|
50
|
|
|
27
|
|
Wolfcamp - Delaware
|
|
28,061
|
|
|
0.4
|
%
|
|
83.1%
|
|
|
4
|
|
|
1
|
|
|
2
|
|
Tuscaloosa Marine Shale
|
|
23,397
|
|
|
0.5
|
%
|
|
93.2
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Haynesville Shale
|
|
7,255
|
|
|
4.1
|
%
|
|
97.1
|
%
|
|
167
|
|
|
325
|
|
|
—
|
|
Granite Wash
|
|
5,031
|
|
|
0.8
|
%
|
|
100.0
|
%
|
|
16
|
|
|
5
|
|
|
<1
|
|
Barnett Shale
|
|
4,164
|
|
|
2.7
|
%
|
|
86.9
|
%
|
|
1
|
|
|
—
|
|
|
2
|
|
Fayetteville Shale
|
|
3,918
|
|
|
0.1
|
%
|
|
100.0%
|
|
|
13
|
|
|
—
|
|
|
—
|
|
Bossier Shale
|
|
1,816
|
|
|
2.8
|
%
|
|
54.1
|
%
|
|
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.
ORRIs
The following table sets forth information about our ORRIs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (Boe/d)
|
|
|
As of December 31, 2016
|
|
For the Year Ended December 31,
|
Resource Play
1
|
|
Acres
|
|
Average
Royalty
Interest
2
|
|
2016
|
|
2015
|
|
2014
|
Wolfcamp - Midland
|
|
125,817
|
|
|
0.3
|
%
|
|
<1
|
|
|
5
|
|
|
3
|
|
Granite Wash
|
|
86,556
|
|
|
1.2
|
%
|
|
155
|
|
|
115
|
|
|
191
|
|
Eagle Ford Shale
|
|
48,920
|
|
|
2.2
|
%
|
|
95
|
|
|
204
|
|
|
96
|
|
Barnett Shale
|
|
36,155
|
|
|
4.9
|
%
|
|
109
|
|
|
158
|
|
|
163
|
|
Haynesville Shale
|
|
14,719
|
|
|
4.4
|
%
|
|
686
|
|
|
1,111
|
|
|
816
|
|
Marcellus Shale
|
|
13,356
|
|
|
2.3
|
%
|
|
37
|
|
|
6
|
|
|
—
|
|
Bakken Shale
|
|
13,210
|
|
|
1.2
|
%
|
|
34
|
|
|
41
|
|
|
27
|
|
Three Forks
|
|
12,530
|
|
|
1.2
|
%
|
|
21
|
|
|
27
|
|
|
18
|
|
Fayetteville Shale
|
|
11,708
|
|
|
4.1
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Bossier Shale
|
|
8,642
|
|
|
4.7
|
%
|
|
28
|
|
|
57
|
|
|
60
|
|
Wolfcamp - Delaware
|
|
4,643
|
|
|
2.1
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Tuscaloosa Marine Shale
|
|
689
|
|
|
7.8
|
%
|
|
<1
|
|
|
—
|
|
|
<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.
Working Interests
The following table sets forth information about our working interests.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Production (Boe/d)
|
|
|
As of December 31, 2016
|
|
For the Year Ended December 31,
|
Resource Play
1
|
|
Gross Acres
2
|
|
Net Acres
2
|
|
2016
|
|
2015
|
|
2014
|
Haynesville Shale
|
|
183,337
|
|
|
53,546
|
|
|
5,077
|
|
|
2,909
|
|
|
3,136
|
|
Bossier Shale
|
|
170,716
|
|
|
52,130
|
|
|
309
|
|
|
135
|
|
|
199
|
|
Three Forks
|
|
50,361
|
|
|
6,732
|
|
|
491
|
|
|
551
|
|
|
491
|
|
Bakken Shale
|
|
50,159
|
|
|
7,105
|
|
|
864
|
|
|
792
|
|
|
855
|
|
Barnett Shale
|
|
13,417
|
|
|
7,747
|
|
|
87
|
|
|
104
|
|
|
124
|
|
Granite Wash
|
|
4,840
|
|
|
1,254
|
|
|
429
|
|
|
537
|
|
|
647
|
|
Wolfcamp - Delaware
|
|
2,642
|
|
|
971
|
|
|
150
|
|
|
23
|
|
|
33
|
|
Eagle Ford Shale
|
|
1,147
|
|
|
87
|
|
|
76
|
|
|
11
|
|
|
—
|
|
Wolfcamp - Midland
|
|
160
|
|
|
4
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Canyon Lime
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
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.
Estimated Proved Reserves
Evaluation and Review of Estimated Proved Reserves
The information included in this Annual Report on Form 10-K relating to our estimated proved oil and natural gas reserves is based upon a reserve report prepared by NSAI, a third-party petroleum engineering firm, as of December 31, 2016.
NSAI provides worldwide petroleum property analysis services for energy clients, financial organizations, and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI summary reserve report incorporated herein is Mr. J. Carter Henson, Jr. Mr. Henson, a Licensed Professional Engineer in the State of Texas (License No. 73964), has been practicing consulting petroleum engineering at NSAI since 1989 and has over 8 years of prior industry experience. He graduated from Rice University in 1981 with a Bachelor of Science Degree in Mechanical Engineering. As technical principal, Mr. Henson meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering evaluations as well as applying SEC and other industry reserves definitions and guidelines. NSAI does not own an interest in us or any of our properties, nor is it employed by us on a contingent basis. A copy of NSAI’s estimated proved reserve report as of December 31, 2016 is attached as an exhibit to this Annual Report.
We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our third-party reserve engineers to ensure the integrity, accuracy, and timeliness of the data used to calculate our estimated proved reserves. Our internal technical team members met with our third-party reserve engineers periodically during the period covered by the above referenced reserve report to discuss the assumptions and methods used in the reserve estimation process. We provided historical information to the third-party reserve engineers for our properties, such as oil and natural gas
production, well test data, realized commodity prices, and operating and development costs. We also provided ownership interest information with respect to our properties. Brock Morris, our Senior Vice President, Engineering and Geology, is primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Morris is a petroleum engineer with approximately 31 years of reservoir-engineering and operations experience.
Our historical proved reserve estimates were prepared in accordance with our internal control procedures. Throughout the year, our technical team met with NSAI to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data used in the reserves evaluation software as well as reviews by our internal engineering staff and management, which include the following:
|
|
•
|
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 ("AFE") 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.
|
Estimation of Proved Reserves
In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. All of our estimated proved reserves as of December 31, 2016 are based on deterministic methods. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by using reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
In order to establish reasonable certainty with respect to our estimated net proved reserves NSAI employed technologies including, but not limited to, electrical logs, radioactivity logs, core analysis, geologic maps, and available down hole pressure and production data, seismic data, and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. In addition to assessing reservoir continuity, geologic data from well logs, core analyses, and seismic data were used to estimate original oil and natural gas in place.
Summary of Estimated Proved Reserves
The following table presents our estimated proved oil and natural gas reserves:
|
|
|
|
|
|
|
As of
December 31, 2016
1
|
As of
December 31, 2015
|
|
(Unaudited)
|
(Unaudited)
|
Estimated proved developed reserves
2
:
|
|
|
Oil (MBbls)
|
18,150
|
|
15,497
|
|
Natural gas (MMcf)
|
223,057
|
|
174,555
|
|
Total (MBoe)
|
55,327
|
|
44,590
|
|
Estimated proved undeveloped reserves
3
:
|
|
|
Oil (MBbls)
|
218
|
|
345
|
|
Natural gas (MMcf)
|
47,282
|
|
29,120
|
|
Total (MBoe)
|
8,098
|
|
5,198
|
|
Estimated proved reserves:
|
|
|
Oil (MBbls)
|
18,368
|
|
15,842
|
|
Natural gas (MMcf)
|
270,339
|
|
203,675
|
|
Total (MBoe)
|
63,425
|
|
49,788
|
|
Percent proved developed
|
87.2
|
%
|
89.6
|
%
|
1
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. Reserve estimates do not include any value for probable or possible reserves that may exist. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas may vary substantially from these estimates.
2
Proved developed reserves of 74 MBoe as of December 31, 2016 were attributable to noncontrolling interests in our consolidated subsidiaries.
3
As of December 31, 2016, no proved undeveloped reserves were attributable to noncontrolling interests in our consolidated subsidiaries.
Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary for the same property. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read Part I, Item 1A. “Risk Factors.”
Additional information regarding our estimated proved reserves can be found in the notes to our consolidated financial statements included elsewhere in this Annual Report and the estimated proved reserve report as of December 31, 2016, which are included as exhibits to this Annual Report.
Estimated Proved Undeveloped Reserves
As of December 31, 2016, our PUDs comprised 218 MBbls of oil and 47,282 MMcf of natural gas, for a total of 8,098 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
The following tables summarizes our changes in PUDs during the year ended December 31, 2016 (in MBoe):
|
|
|
|
|
Proved Undeveloped Reserves
|
|
(Unaudited)
|
Balance as of December 31, 2015
|
5,198
|
|
Acquisitions of reserves
|
—
|
|
Extensions and discoveries
|
7,403
|
|
Revisions of previous estimates
|
548
|
|
Transfers to estimated proved developed
|
(5,051
|
)
|
Balance as of December 31, 2016
|
8,098
|
|
There were no PUD reserves acquired during the year ended December 31, 2016. New PUD reserves totaling 7,403 MBoe were added during the year ended December 31, 2016, resulting primarily from development activities in the Haynesville/Bossier and Bakken plays, and proposals for new wells from our operators in those plays.
During the year ended December 31, 2016, we had reductions of 69 Mboe related to wells removed from PUD status as a result of stale permits or updated operator information. This was offset by increases in previous estimates of 617 Mboe based on performance from offset and analog production. This resulted in a total upward revision of 548 Mboe comprised of an increase of 3,507 MMcf natural gas reserves and a decrease of 36 Mbbl of oil reserves.
Costs incurred relating to the development of locations that were classified as PUDs at December 31, 2015 were $28.9 million during the year ended December 31, 2016. Additionally, during the year ended December 31, 2016, we incurred $42.9 million drilling and completing other wells which were not classified as PUDs as of December 31, 2015. Estimated future development costs during the year ended December 31, 2017 relating to the development of PUD reserves at December 31, 2016 are projected to be approximately $35.9 million. All of our PUD drilling locations as of December 31, 2016 are scheduled to be drilled within five years or less from the date the reserves were initially booked as proved undeveloped reserves.
We generally do not have evidence of approval of our operators’ development plans. As a result, our proved undeveloped reserve estimates are limited to those relatively few locations for which we have received and approved an authorization for expenditure and which remained undrilled as of December 31, 2016. As of December 31, 2016, approximately 12.8% of our total proved reserves were classified as PUDs.
Oil and Natural Gas Production Prices and Production Costs
Production and Price History
For the year ended December 31, 2016, 31.7% of our production and 53.7% of our oil and natural gas revenues were related to oil and condensate production and sales. During the same period, natural gas and natural gas liquids were 68.3% of our production and 46.3% of our oil and natural gas revenues.
The following table sets forth information regarding production of oil and natural gas and certain price and cost information for each of the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
Production:
|
|
|
|
|
|
|
|
|
|
Oil and condensate (MBbls)
1
|
|
3,680
|
|
|
3,565
|
|
|
3,005
|
|
Natural gas (MMcf)
1
|
|
47,498
|
|
|
41,389
|
|
|
42,273
|
|
Total (MBoe)
|
|
11,596
|
|
|
10,463
|
|
|
10,051
|
|
Average daily production (MBoe/d)
|
|
31.7
|
|
|
28.7
|
|
|
27.5
|
|
Realized Prices
2
:
|
|
|
|
|
|
|
|
|
|
Oil and condensate (per Bbl)
|
|
$
|
38.69
|
|
|
$
|
45.87
|
|
|
$
|
85.65
|
|
Natural gas and natural gas liquids (per Mcf)
1
|
|
$
|
2.59
|
|
|
$
|
2.80
|
|
|
$
|
4.91
|
|
Unit Cost per Boe:
|
|
|
|
|
|
|
|
|
|
Production costs and ad valorem taxes
|
|
$
|
3.06
|
|
|
$
|
3.42
|
|
|
$
|
4.93
|
|
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.
Productive Wells
Productive wells consist of producing wells, wells capable of production, and exploratory, development, or extension wells that are not dry wells. As of December 31, 2016, we owned mineral and royalty interests or working interests in 55,260 productive wells, which consisted of 34,645 oil wells and 20,615 natural gas wells. As of December 31, 2016, we owned mineral and royalty interests in 49,942 productive wells, which consisted of 33,799 oil wells and 16,143 natural gas wells, and working interests in 8,577 gross productive wells and 328 net productive wells, which consisted of 2,981 gross (58 net) productive oil wells and 5,596 gross (270 net) productive natural gas wells. We own both mineral and royalty interests and working interests in 3,259 of these wells.
Acreage
Mineral and Royalty Interests
The following table sets forth information relating to our acreage for our mineral interests as of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
State
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
Texas
|
|
345,935
|
|
|
3,942,268
|
|
|
4,288,203
|
|
Mississippi
|
|
4,816
|
|
|
2,389,431
|
|
|
2,394,247
|
|
Alabama
|
|
2,699
|
|
|
2,045,661
|
|
|
2,048,360
|
|
Arkansas
|
|
4,767
|
|
|
1,264,324
|
|
|
1,269,091
|
|
North Dakota
|
|
16,041
|
|
|
994,028
|
|
|
1,010,069
|
|
Nevada
|
|
—
|
|
|
792,428
|
|
|
792,428
|
|
Florida
|
|
—
|
|
|
744,341
|
|
|
744,341
|
|
Louisiana
|
|
35,354
|
|
|
518,604
|
|
|
553,958
|
|
Montana
|
|
20,765
|
|
|
479,028
|
|
|
499,793
|
|
Oklahoma
|
|
117,952
|
|
|
367,857
|
|
|
485,809
|
|
Other
|
|
81,557
|
|
|
1,348,069
|
|
|
1,429,626
|
|
Total
|
|
629,886
|
|
|
14,886,039
|
|
|
15,515,925
|
|
The following table sets forth information relating to our acreage for our NPRIs as of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
State
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
Texas
|
|
203,655
|
|
|
818,363
|
|
|
1,022,018
|
|
Montana
|
|
11,684
|
|
|
169,409
|
|
|
181,093
|
|
Mississippi
|
|
10,506
|
|
|
62,798
|
|
|
73,304
|
|
Louisiana
|
|
10,508
|
|
|
62,203
|
|
|
72,711
|
|
North Dakota
|
|
18,540
|
|
|
18,616
|
|
|
37,156
|
|
Arkansas
|
|
3,974
|
|
|
29,070
|
|
|
33,044
|
|
Wyoming
|
|
1,360
|
|
|
17,160
|
|
|
18,520
|
|
New Mexico
|
|
14,289
|
|
|
960
|
|
|
15,249
|
|
Oklahoma
|
|
6,976
|
|
|
5,749
|
|
|
12,725
|
|
Kansas
|
|
9,042
|
|
|
2,983
|
|
|
12,025
|
|
Other
|
|
367
|
|
|
3,041
|
|
|
3,408
|
|
Total
|
|
290,901
|
|
|
1,190,352
|
|
|
1,481,253
|
|
The following table sets forth information relating to our acreage for our ORRIs as of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
State
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
Montana
|
|
295,401
|
|
|
165,496
|
|
|
460,897
|
|
Texas
|
|
292,352
|
|
|
57,002
|
|
|
349,354
|
|
Wyoming
|
|
133,702
|
|
|
40,045
|
|
|
173,747
|
|
Oklahoma
|
|
157,339
|
|
|
2,006
|
|
|
159,345
|
|
Utah
|
|
40,510
|
|
|
26,163
|
|
|
66,673
|
|
New Mexico
|
|
46,151
|
|
|
13,868
|
|
|
60,019
|
|
Michigan
|
|
55,272
|
|
|
1,239
|
|
|
56,511
|
|
Colorado
|
|
27,108
|
|
|
9,899
|
|
|
37,007
|
|
Louisiana
|
|
15,264
|
|
|
17,886
|
|
|
33,150
|
|
Alaska
|
|
7,664
|
|
|
12,375
|
|
|
20,039
|
|
Other
|
|
74,448
|
|
|
14,641
|
|
|
89,089
|
|
Total
|
|
1,145,211
|
|
|
360,620
|
|
|
1,505,831
|
|
Working Interests
The following table sets forth information relating to our acreage for our non-operated working interests as of December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
State
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
Texas
|
|
196,818
|
|
|
53,438
|
|
|
148,661
|
|
|
44,391
|
|
|
345,479
|
|
|
97,829
|
|
North Dakota
|
|
43,369
|
|
|
6,381
|
|
|
7,564
|
|
|
763
|
|
|
50,933
|
|
|
7,144
|
|
Louisiana
|
|
31,608
|
|
|
4,114
|
|
|
14,408
|
|
|
1,436
|
|
|
46,016
|
|
|
5,550
|
|
Wyoming
|
|
22,290
|
|
|
4,168
|
|
|
6,358
|
|
|
1,596
|
|
|
28,648
|
|
|
5,764
|
|
Michigan
|
|
13,208
|
|
|
1,330
|
|
|
79
|
|
|
—
|
|
|
13,287
|
|
|
1,330
|
|
Oklahoma
|
|
11,703
|
|
|
3,070
|
|
|
10
|
|
|
3
|
|
|
11,713
|
|
|
3,073
|
|
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
|
|
6,536
|
|
|
2,146
|
|
|
1,494
|
|
|
361
|
|
|
8,030
|
|
|
2,507
|
|
Total
|
|
348,135
|
|
|
87,587
|
|
|
180,535
|
|
|
48,685
|
|
|
528,670
|
|
|
136,272
|
|
The following table lists the net undeveloped acres, the net acres expiring in the years ending December 31, 2017, 2018, and 2019, and, where applicable, the net acres expiring that are subject to extension options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 Expirations
|
|
2018 Expirations
|
|
2019 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.
|
48,685
|
|
|
17,204
|
|
|
151
|
|
|
12,491
|
|
|
—
|
|
|
1,652
|
|
|
281
|
|
Drilling Results for Our Working Interests
The following table sets forth information with respect to the number of wells completed on our properties during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, the quantities of reserves found, and the economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
Gross development wells:
|
|
|
|
|
|
|
|
|
|
Productive
|
|
47.0
|
|
|
74.0
|
|
|
222.0
|
|
Dry
|
|
—
|
|
|
1.0
|
|
|
1.0
|
|
Total
|
|
47.0
|
|
|
75.0
|
|
|
223.0
|
|
Net development wells:
|
|
|
|
|
|
|
|
|
|
Productive
|
|
4.7
|
|
|
2.9
|
|
|
7.3
|
|
Dry
|
|
—
|
|
|
<0.1
|
|
|
—
|
|
Total
|
|
4.7
|
|
|
2.9
|
|
|
7.3
|
|
Gross exploratory wells:
|
|
|
|
|
|
|
|
|
|
Productive
|
|
—
|
|
|
—
|
|
|
1.0
|
|
Dry
|
|
—
|
|
|
—
|
|
|
1.0
|
|
Total
|
|
—
|
|
|
—
|
|
|
2.0
|
|
Net exploratory wells:
|
|
|
|
|
|
|
|
|
|
Productive
|
|
—
|
|
|
—
|
|
|
<0.1
|
|
Dry
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
—
|
|
|
—
|
|
|
<0.1
|
|
As of December 31, 2016, we had 20 wells in the process of drilling, completing or dewatering, or shut in awaiting infrastructure that are not reflected in the above table.
Environmental Matters
Oil and natural gas exploration, development, and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, which could materially adversely affect our business and our prospects. Numerous federal, state, and local governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”), issue regulations that often require compliance measures that carry substantial administrative, civil, and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities, and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive, and other protected areas, require action to prevent, or remediate pollution from current or historic operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses, and authorizations, require that additional pollution controls be installed, and impose substantial liabilities for pollution resulting from operations. The strict, joint, and several liability nature of such laws and regulations could impose liability upon our operators, or us as working-interest owners if the operator fails to perform, regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, or other waste products into the environment. In addition, many environmental statues contain citizen suit provisions, and environmental groups frequently use these provisions to oppose oil and natural gas exploration and development activities and related projects. Changes in environmental laws and regulations occur frequently, and any changes that impact our operators and result in more stringent and costly pollution control or waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our business and prospects. Below is a summary of environmental laws applicable to our operators.
Waste Handling
The Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non- hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development, and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute “solid wastes” that are subject to less stringent non-hazardous waste requirements. However, it is possible that RCRA could be amended or the EPA or state environmental agencies could adopt policies to require oil and natural gas exploration, development, and production wastes to become subject to more stringent waste handling requirements. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. Removal of RCRA’s exemption for exploration and production wastes has the potential to significantly increase waste disposal costs, which in turn will result in increased operating costs and could adversely impact production on our properties. Administrative, civil, and criminal penalties can be imposed for failure to comply with waste handling requirements. Any changes in the laws and regulations could have a material adverse effect on our operators’ capital expenditures and operating expenses, which in turn could affect production from our properties and adversely affect our business and prospects.
Remediation of Hazardous Substances
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and analogous state laws generally impose strict, joint, and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility (which can include working-interest owners), a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Oil and natural gas exploration and production activities on our properties use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold our operators, or
us as working-interest owners if the operator fails to perform, responsible under CERCLA and comparable state statutes for all or part of the costs to clean-up sites at which these “hazardous substances” have been released.
Water Discharges
The Federal Water Pollution Control Act of 1972, also known as the “Clean Water Act” (“CWA”), the Safe Drinking Water Act (“SDWA”), the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In September 2015, new EPA and U.S. Army Corps of Engineers rules defining the scope of the EPA’s and the Corps’ jurisdiction became effective. To the extent the rule expands the scope of the CWA’s jurisdiction, our operators could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs, and implementation of the rule has been stayed pending resolution of the court challenge. In addition, spill prevention, control, and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges.
The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil into surface waters.
In addition, while the SDWA, generally excludes hydraulic fracturing from the definition of underground injection, it does not exclude hydraulic fracturing involving the use of diesel fuels. In 2014, the EPA issued draft permitting guidance governing hydraulic fracturing with diesel fuels. While our operators do not use diesel fuels in their hydraulic fracturing fluids, they may become subject to federal permitting under SDWA if their fracturing formula changes. In addition, the SDWA grants the EPA broad authority to take action to protect public health when an underground source of drinking water is threatened with pollution that presents an imminent and substantial endangerment to humans, which could result in orders prohibiting or limiting operations. Moreover, the SDWA also regulates saltwater disposal wells under the Underground Injection Control Program. Recent concerns related to the operation of saltwater disposal wells and induced seismicity have led some states to impose limits on the total volume of produced water such wells can dispose of, order disposal wells to cease operations, or limited the construction of new wells. These seismic events have also resulted in environmental groups and local residents filing lawsuits against operators in areas where the events occur seeking damages and injunctions limiting or prohibiting saltwater disposal well construction activities and operations. A lack of saltwater disposal wells in production areas could result in increased disposal costs for our operators if they are forced to transport produced water by truck, pipeline, or other method over long distances.
Noncompliance with the Clean Water Act, SDWA, or the OPA may result in substantial administrative, civil, and criminal penalties, as well as injunctive obligations, all of which could affect production from our properties and adversely affect our business and prospects.
Air Emissions
The federal Clean Air Act and comparable state laws and regulations regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in August 2012, the EPA adopted new regulations under the Clean Air Act that established new emission control requirements for oil and natural gas production and processing operations. In addition, in October 2015, the EPA lowered the National Ambient Air Quality Standard, (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8- hour primary and secondary standards. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit the ability of our operators to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. More recently, in June 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable
to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for oil and natural gas producers and impact production on our properties, and federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas exploration and development projects. All of these factors could impact production on our properties and adversely affect our business and results of operations.
Climate Change
In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. These EPA rulemakings could adversely affect operations on our properties and restrict or delay the ability of our operators to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include gathering and boosting facilities as well as GHG emissions from completions and workovers of hydraulically fractured wells. Also, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The Bureau of Land Management (“BLM”) finalized similar rules in November 2016 that seek to limit methane emissions from oil and natural gas development on federal and tribal lands through limitations on venting and flaring activities. However, both the U.S. House of Representatives and the Senate have introduced resolutions seeking to repeal the BLM methane rules under the Congressional Review Act and future implementation of the BLM methane rules is uncertain. In any event, the BLM and the EPA methane rules have substantial similarities with respect to pollution control equipment and leak detection and repair (“LDAR”) requirements. These rules could result in increased compliance costs for our operators and require them to make expenditures to purchase pollution control equipment and hire additional personnel to assist with complying with LDAR requirements, such as increased frequency of inspections and repairs for certain processes and equipment. Consequently, these and other regulations related to controlling GHG emissions could have an adverse impact on our business and results of operations.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation, a number of state and regional GHG cap and trade programs have emerged. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas produced from our properties and lower the value of our reserves. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any of these effects were to occur, they could have a material adverse effect on our properties and operations.
Hydraulic Fracturing
Our operators engage in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions, but recently the EPA and other federal agencies have asserted jurisdiction over certain aspects of hydraulic fracturing. For example, the EPA has issued final regulations under the federal Clean Air Act governing performance standards, including standards for the capture of air released during hydraulic fracturing; proposed in April 2015 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants; and issued in May 2014 an Advanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and tribal lands including, for example, notice to and pre approval by BLM of the proposed hydraulic fracturing activities; development and pre approval by BLM of a plan for managing and containing flowback fluids and produced water recovered during the hydraulic fracturing process; implementation of measures designed to protect usable water from hydraulic fracturing activities; and public disclosure of the chemicals used in the hydraulic fracturing fluid. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals, or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The EPA has not proposed to take any action in response to the report’s findings.
Several states where we own interests in oil and gas producing properties, including Colorado, North Dakota, Louisiana, Oklahoma, and Texas, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances or require the disclosure of the composition of hydraulic-fracturing fluids. For example, in Texas, the Texas Railroad Commission (“RRC”) published a final rule in October 2014 governing permitting or re-permitting of disposal wells that requires, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. These existing or any new legal requirements establishing seismic permitting requirements or similar restrictions on the construction or operation of disposal wells for the injection of produced water likely will result in added costs to comply and affect our operators’ rate of production, which in turn could have a material adverse effect on our results of operations and financial position. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where our operators conduct operations, our operators may incur substantial costs to comply with these requirements, which may be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, or production activities and perhaps even be precluded from the drilling of wells.
There has been increasing public controversy regarding hydraulic fracturing with regard to increased risks of induced seismicity, the use of fracturing fluids, impacts on drinking water supplies, use of water, and the potential for impacts to surface water, groundwater, and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic-fracturing practices. If new laws or regulations are adopted that significantly restrict hydraulic fracturing, those laws could make it more difficult or costly for our operators to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities on our properties could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, and also to attendant permitting delays and potential increases in costs. Legislative changes could cause operators to incur substantial compliance costs. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.
Occupational Safety and Health Act
The OSHA and comparable state laws and regulations govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations, and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in operations on our properties and that this information be provided to employees, state and local government authorities, and citizens.
Endangered Species
The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Some of our properties may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotected species may later be designated as threatened or endangered in areas where we hold mineral interests. This could cause our operators to incur increased costs arising from species protection measures, delay the completion of exploration and production activities, and/or result in limitations on operating activities that could have an adverse impact on our business.
Title to Properties
Prior to completing an acquisition of oil and natural gas properties, we perform title reviews on high-value tracts. Our title reviews are meant to confirm quantum of oil and natural gas properties being acquired, lease status, and royalties as well as encumbrances and other related burdens. Depending on the materiality of properties, we may obtain a title opinion if we believe additional title due diligence is necessary. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.
In addition to our initial title work, our operators conduct a thorough title examination prior to leasing and drilling a well. Should our operators’ title work uncover any title defects, either we or our operators will perform curative work with respect to such defects. Our operators generally will not commence drilling operations on a property until any material title defects on such property have been cured.
We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions, and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens, and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.
Marketing and Major Customers
If we were to lose a significant customer, such loss could impact revenue derived from our mineral-and-royalty-interest or working-interest properties. The loss of any single lessee is mitigated by our diversified customer base. The following table indicates our significant customers that accounted for 10% or more of our total revenues for the periods indicated:
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For the Year Ended December 31,
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2016
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2015
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2014
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Exxon Mobil
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11.0
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%
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*
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*
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Chesapeake Energy Corporation
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*
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*
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10.0
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%
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*
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Accounted for less than 10% of total revenues for the period indicated.
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Competition
The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition - of minerals and oil and natural gas leases, and personnel required to find and produce reserves. Many companies not only explore for and produce oil and natural gas, but also conduct midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis. Certain of our competitors may possess financial or other resources substantially larger than we possess. Our ability to acquire additional minerals and properties and to discover reserves in the future will be dependent upon our ability to identify and evaluate suitable acquisition prospects and to consummate transactions in a highly competitive environment. Oil and natural gas products compete with other sources of energy available to customers, primarily based on price. These alternate sources of energy include coal, nuclear, solar and wind. Changes in the availability or price of oil and natural gas or other sources of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other sources of energy may affect the demand for oil and natural gas.
Seasonal Nature of Business
Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.
Employees
We are managed and operated by the board of directors and executive officers of our general partner. All of our employees, including our executive officers, are employees of Black Stone Natural Resources Management Company (“Black Stone Management”). As of December 31, 2016, Black Stone Management had 108 full-time employees. None of Black Stone Management’s employees are represented by labor unions or covered by any collective bargaining agreements.
Facilities
Our principal office location is in Houston, Texas and consists of 55,862 square feet of leased space.
ITEM 1A.
Risk Factors
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks were to occur, our financial condition, results of operations, cash flows, and ability to make distributions could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline, and holders of our units could lose all or part of their investment.
Risks Related to Our Business
We may not generate sufficient cash from operations after establishment of cash reserves to pay the minimum quarterly distribution on our common and subordinated units. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our preferred units are outstanding.
We may not generate sufficient cash from operations each quarter to pay the full minimum quarterly distribution to our common and subordinated unitholders. Our preferred unitholders have priority with respect to rights to share in distributions over our common and subordinated unitholders. Furthermore, our partnership agreement does not require us to pay distributions to our common and subordinated unitholders on a quarterly basis or otherwise. The amount of cash to be distributed each quarter will be determined by the board of directors of our general partner.
The amount of cash we have to distribute each quarter principally depends upon the amount of revenues we generate, which are largely dependent upon the prices that our operators realize from the sale of oil and natural gas. The actual amount of cash we will have to distribute each quarter will be reduced by principal and interest payments on our outstanding debt, working-capital requirements, and other cash needs. In addition, we may restrict distributions, in whole or in part, to fund
replacement capital expenditures, acquisitions, and participation in working interests. If over the long term we do not retain cash for replacement capital expenditures in amounts necessary to maintain our asset base, a portion of future distributions will represent a return of capital and the value of our common units will be adversely affected, which will eventually cause our cash distributions per unit to decrease. Withholding cash for our capital expenditures may have an adverse impact on the cash distributions in the quarter in which amounts are withheld.
For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy.”
The amount of cash we distribute to holders of our units depends primarily on our cash generated from operations and not our profitability, which may prevent us from making cash distributions during periods when we record net income.
The amount of cash we distribute depends primarily upon our cash generated from operations and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods in which we record net losses for financial accounting purposes and may be unable to make cash distributions during periods in which we record net income.
The volatility of oil and natural gas prices due to factors beyond our control greatly affects our financial condition, results of operations, and cash distributions to unitholders.
Our revenues, operating results, cash distributions to unitholders, and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty, and a variety of additional factors that are beyond our control, including:
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the domestic and foreign supply of and demand for oil and natural gas;
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market expectations about future prices of oil and natural gas;
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the level of global oil and natural gas exploration and production;
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the cost of exploring for, developing, producing, and delivering oil and natural gas;
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the price and quantity of foreign imports;
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political and economic conditions in oil producing regions, including the Middle East, Africa, South America, and Russia;
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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
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trading in oil and natural gas derivative contracts;
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the level of consumer product demand;
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weather conditions and natural disasters;
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technological advances affecting energy consumption;
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domestic and foreign governmental regulations and taxes;
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the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;
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the proximity, cost, availability, and capacity of oil and natural gas pipelines and other transportation facilities;
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the price and availability of alternative fuels; and
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overall domestic and global economic conditions.
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These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the five years prior to December 31, 2016, the spot price for West Texas Intermediate light sweet crude oil, which we refer to as WTI has ranged from a high of $110.62 per Bbl in 2013 to a low of $26.19 per Bbl in 2016. During the same period, the Henry Hub spot market price of natural gas has ranged from a low of $1.49 in 2016 to a high of $8.15 per MMBtu in 2014. During 2016, the WTI spot price of oil ranged from $26.19 to $54.01 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.49 to $3.80 per MMBtu. On December 31, 2014, the WTI spot price for oil was $53.45 per Bbl and the Henry Hub spot market price of natural gas was $3.14 per MMBtu. On December 31, 2015, the WTI spot price for oil was $37.13 per Bbl and the Henry Hub spot market price of natural gas was $2.28 per MMBtu. On December 31, 2016, the WTI spot price for oil was $53.75 per Bbl, and the Henry Hub spot market price of natural gas was $3.71 per MMBtu.
Any prolonged substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders. We may use various derivative instruments in connection with anticipated oil and natural gas sales to minimize the impact of commodity price fluctuations. However, we cannot always hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.
In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that can be produced economically by our operators. This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.
Oil prices have declined substantially from historical highs and may remain depressed for the foreseeable future. Approximately 53.7% of our 2016 oil and natural gas revenues were derived from oil and condensate sales. Any additional decreases in prices of oil may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all of our outstanding common and subordinated units, perhaps materially.
The spot WTI market price at Cushing, Oklahoma has declined from $98.17 per Bbl on December 31, 2013 to $53.75 per Bbl on December 31, 2016. The reduction in price has been caused by many factors, including substantial increases in U.S. oil production from unconventional (shale) reservoirs, with limited increases in demand. If prices for oil continue to remain depressed for lengthy periods, we may be required to further write down the value of our oil and natural gas properties in addition to impairments taken during 2015 and 2016, and some of our undeveloped locations may no longer be economically viable. In addition, sustained low prices for oil will continue to negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our bank credit facility and reduce the amounts of cash we would otherwise have available to pay expenses, fund capital expenditures, make distributions to our unitholders, and service our indebtedness.
Natural gas prices have declined substantially from historical highs and are expected to remain depressed for the foreseeable future. Approximately 68.3% of our 2016 total production was natural gas, on a “Btu-equivalent” basis. Any additional decreases in prices of natural gas may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all of our outstanding common and subordinated units, perhaps materially.
During the nine years prior to December 31, 2016, natural gas prices at Henry Hub have ranged from a high of $13.31 per MMBtu in 2008 to a low of $1.49 per MMBtu in 2016. On December 31, 2016, the Henry Hub spot market price of natural gas was $3.71 per MMBtu. The reduction in prices has been caused by many factors, including increases in natural gas production from unconventional (shale) reservoirs, without an offsetting increase in demand. The expected increase in natural gas production, based on reports from the EIA, could cause the prices for natural gas to remain at current levels or fall to lower levels. If prices for natural gas continue to remain depressed for lengthy periods, we may be required to further write down the value of our oil and natural gas properties in addition to impairments taken during 2015 and 2016, and some of our undeveloped locations may no longer be economically viable. In addition, sustained low prices for natural gas will continue to negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our bank credit facility and reduce the amounts of cash we would otherwise have available to pay expenses, make distributions to our unitholders, and service our indebtedness.
Our failure to successfully identify, complete, and integrate acquisitions could adversely affect our growth, results of operations, and cash distributions to unitholders.
We depend partly on acquisitions to grow our reserves, production, and cash generated from operations. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data, and other information, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires an assessment of several factors, including:
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future oil and natural gas prices and their applicable differentials;
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potential environmental and other liabilities.
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The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, if applicable, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain financing. In addition, compliance with regulatory requirements may impose substantial additional obligations on our operators, causing them to expend additional time and resources in compliance activities, and potentially increase our operators’ exposure to penalties or fines for non-compliance with additional legal requirements. Further, the process of integrating acquired assets may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources.
No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully, or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations, and cash distributions to unitholders.
Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.
Even if we do make acquisitions that we believe will increase our cash generated from operations, these acquisitions may nevertheless result in a decrease in our cash distributions per unit. Any acquisition involves potential risks, including, among other things:
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the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, operating expenses, and costs;
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a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;
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a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
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the assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which any indemnity we receive is inadequate;
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mistaken assumptions about the overall cost of equity or debt;
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our ability to obtain satisfactory title to the assets we acquire;
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an inability to hire, train, or retain qualified personnel to manage and operate our growing business and assets; and
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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.
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We depend on various unaffiliated operators for all of the exploration, development, and production on the properties underlying our mineral and royalty interests and non-operated working interests. Substantially all of our revenue is derived from the sale of oil and natural gas production from producing wells in which we own a royalty interest or a non-operated working interest. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on our results of operations.
Our assets consist of mineral and royalty interests and non-operated working interests. For the year ended December 31, 2016, we received revenue from over 1,000 operators. The failure of our operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues. Our operators are often not obligated to undertake any development activities other than those required to maintain their leases on our acreage. In the absence of a specific contractual obligation, any development and production activities will be subject to
their reasonable discretion. Our operators could determine to drill and complete fewer wells on our acreage than is currently expected. The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that will be largely outside of our control, including:
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the capital costs required for drilling activities by our operators, which could be significantly more than anticipated;
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the ability of our operators to access capital;
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prevailing commodity prices;
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the availability of suitable drilling equipment, production and transportation infrastructure, and qualified operating personnel;
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the operators’ expertise, operating efficiency, and financial resources;
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approval of other participants in drilling wells;
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the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;
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the selection of technology;
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the selection of counterparties for the marketing and sale of production; and
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the rate of production of the reserves.
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The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our results of operations and cash distributions to our unitholders. Sustained reductions in production by the operators on our properties may also adversely affect our results of operations and cash distributions to unitholders.
We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.
A failure on the part of the operators to make royalty payments gives us the right to terminate the lease, repossess the property, and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to a proceeding under title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another operator. In the event that the operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new operator, the replacement operator may not achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced.
Acquisitions, funding our working-interest participation program, and our operators’ development activities of our leases will require substantial capital, and we and our operators may be unable to obtain needed capital or financing on satisfactory terms or at all.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in connection with the acquisition of mineral and royalty interests and participation in our working-interest participation program. To date, we have financed capital expenditures primarily with funding from cash generated by operations, limited borrowings under our credit facility, and the issuance of equity securities.
In the future, we may restrict distributions to fund acquisitions and participation in our working interests but eventually we may need capital in excess of the amounts we retain in our business or borrow under our credit facility. We cannot assure you that we will be able to access external capital on terms favorable to us or at all. If we are unable to fund our capital requirements, we may be unable to complete acquisitions, take advantage of business opportunities, or respond to competitive pressures, any of which could have a material adverse effect on our results of operation and cash distributions to unitholders.
Most of our operators are also dependent on the availability of external debt and equity financing sources to maintain their drilling programs. If those financing sources are not available to the operators on favorable terms or at all, then we expect the development of our properties to be adversely affected. If the development of our properties is adversely affected, then revenues from our mineral and royalty interests and non-operated working interests may decline.
Unless we replace the oil and natural gas produced from our properties, our cash generated from operations and our ability to make distributions to our common and subordinated unitholders could be adversely affected.
Producing oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and our operators’ production thereof and our cash generated from operations and ability to make distributions are highly dependent on the successful development and exploitation of our current reserves. The production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to find, acquire, or develop additional reserves to replace the current and future production of our properties at economically acceptable terms, which would adversely affect our business, financial condition, results of operations, and cash distributions to our common and subordinated unitholders.
We either have little or no control over the timing of future drilling with respect to our mineral and royalty interests and non-operated working interests.
Our proved undeveloped reserves may not be developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations, and the decision to pursue development of a proved undeveloped drilling location will be made by the operator and not by us. The reserve data included in the reserve report of our engineer assume that substantial capital expenditures are required to develop the reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled, or that the results of the development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop our reserves, or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our undeveloped reserves as unproved reserves.
Project areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.
Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations, and cash distributions to unitholders may be adversely affected.
Our operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
The ability of our operators to drill and develop identified potential drilling locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results, and the availability of water. Further, our operators’ identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will not enable our operators to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, our operators may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If our operators drill additional wells that they identify as dry holes in current and future drilling locations, their drilling success rate may decline and materially harm their business as well as ours.
We cannot assure you that the analogies our operators draw from available data from the wells on our acreage, more fully explored locations, or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which our reserves are located may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations our operators have identified will ever be drilled or if our operators will be able to produce oil or natural gas from these or any other potential drilling locations. As such, the actual drilling activities of our operators may materially differ from those presently identified, which could adversely affect our business, results of operation, and cash distributions to unitholders.
The unavailability, high cost, or shortages of rigs, equipment, raw materials, supplies, or personnel may restrict or result in increased costs for operators related to developing and operating our properties.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, and personnel. When shortages occur, the costs and delivery times of rigs, equipment, and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, our operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. If our operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking
and completion services, and production equipment could delay or restrict our operators’ exploration and development operations, which in turn could have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders.
The marketability of oil and natural gas production is dependent upon transportation, pipelines, and refining facilities, which neither we nor many of our operators control. Any limitation in the availability of those facilities could interfere with our or our operators’ ability to market our or our operators’ production and could harm our business.
The marketability of our or our operators’ production depends in part on the availability, proximity, and capacity of pipelines, tanker trucks, and other transportation methods, and processing and refining facilities owned by third parties. The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage, or lack of available capacity on these systems, tanker truck availability, and extreme weather conditions. Also, the shipment of our or our operators’ oil and natural gas on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we or our operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing, or refining-facility capacity could reduce our or our operators’ ability to market oil production and have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders. Our or our operators’ access to transportation options and the prices we or our operators receive can also be affected by federal and state regulation—including regulation of oil production, transportation, and pipeline safety—as well by general economic conditions and changes in supply and demand. In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal, and local laws that could adversely affect the cost, manner, or feasibility of conducting our business.
Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries, and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates, and the timing of development expenditures may be incorrect. Our estimates of proved reserves and related valuations as of December 31, 2016 were prepared by NSAI, a third-party petroleum engineering firm, which conducted a detailed review of all of our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing, and production. Also, certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves and future cash generated from operations. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that are ultimately recovered being different from our reserve estimates.
The estimates of reserves as of December 31, 2016 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the year ended December 31, 2016 in accordance with the SEC guidelines applicable to reserve estimates for those periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy, and energy-generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations, and cash distributions to unitholders.
We rely on a few key individuals whose absence or loss could adversely affect our business.
Many key responsibilities within our business have been assigned to a small number of individuals. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team could disrupt our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.
The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
Our operators use the latest drilling and completion techniques in their operations, and these techniques come with inherent risks. When drilling horizontal wells, operators risk not landing the well bore in the desired drilling zone and straying from the desired drilling zone. When drilling horizontally through a formation, operators risk being unable to run casing through the entire length of the well bore and being unable to run tools and other equipment consistently through the horizontal well bore. Risks that our operators face while completing wells include being unable to fracture stimulate the planned number of stages, to run tools the entire length of the well bore during completion operations, and to clean out the well bore after completion of the final fracture stimulation stage. In addition, to the extent our operators engage in horizontal drilling, those activities may adversely affect their ability to successfully drill in identified vertical drilling locations. Furthermore, certain of the new techniques that our operators may adopt, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before these wells begin producing. The results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently our operators will be less able to predict future drilling results in these areas.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our operators’ drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties, our operating and financial results in these areas may be lower than we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline, and our results of operations and cash distributions to unitholders could be adversely affected.
Oil and natural gas operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive, and failure to comply could result in significant liabilities, which could reduce cash distributions to our unitholders.
Operations on the properties in which we hold interests are subject to various federal, state, and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage and transportation of oil and natural gas, as well as the remediation, emission, and disposal of oil and natural gas wastes, by-products thereof, and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state, and local laws and regulations primarily relating to protection of worker health and safety, natural resources, and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, or criminal penalties, permit revocations, requirements for additional pollution controls, and injunctions limiting or prohibiting some or all of the operations on our properties. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management.
Laws and regulations governing exploration and production may also affect production levels. Our operators must comply with federal and state laws and regulations governing conservation matters, including:
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provisions related to the unitization or pooling of the oil and natural gas properties;
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the establishment of maximum rates of production from wells;
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the plugging and abandonment of wells; and
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the removal of related production equipment.
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Additionally, federal and state regulatory authorities may expand or alter applicable pipeline-safety laws and regulations, compliance with which may require increased capital costs for third-party oil and natural gas transporters. These transporters may attempt to pass on such costs to our operators, which in turn could affect profitability on the properties in which we own mineral and royalty interests.
Our operators must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity.
Our operators may be required to make significant expenditures to comply with the governmental laws and regulations described above. We believe the trend of more expansive and stricter environmental legislation and regulations will continue.
Please read Part I, Items 1 and 2. “Business and Properties—Environmental Matters” for a description of the laws and regulations that affect our operators and that may affect us. These and other potential regulations could increase the operating costs of our operators and delay production, which could reduce the amount of cash distributions to our unitholders.
Louisiana mineral servitudes are subject to reversion to the surface owner after ten years’ nonuse.
We own mineral servitudes covering several hundred thousand acres in Louisiana. A mineral servitude is created in Louisiana when the mineral rights are separated from the ownership of the surface, whether by sale or reservation. These mineral servitudes, once created, are subject to a ten-year prescription of nonuse. During the ten-year period, the mineral-servitude owner has to conduct good-faith operations on the servitude for the discovery and production of minerals, or the mineral servitude “prescribes,” and the mineral rights associated with that servitude revert to the surface owner. A good-faith operation for the discovery and production of minerals, even one resulting in a dry hole, conducted within the ten-year period will interrupt the prescription of nonuse and restart the running of the ten-year prescriptive period. If the operation results in production, prescription is interrupted as long as the production continues or operations are conducted in good faith to secure or restore production. If any of our mineral servitudes are prescribed by operation of Louisiana law, our operating results may be adversely affected.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs, additional operating restrictions or delays, and fewer potential drilling locations.
Our operators engage in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic-fracturing process is typically regulated by state oil and natural gas commissions. The U.S. Environmental Protection Agency (“EPA”), however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program and issued guidance in February 2014 applicable to hydraulic fracturing involving the use of diesel fuel. The EPA has also issued final regulations under the federal Clean Air Act governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; finalized rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants; and issued in May 2015 an Advanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, the Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and tribal lands including, for example, notice to and by BLM of the proposed hydraulic fracturing activities; development and by BLM of a plan for managing and containing flowback fluids and produced water recovered during the hydraulic fracturing process; implementation of measures designed to protect usable water from hydraulic fracturing activities; and public disclosure of the chemicals used in the hydraulic fracturing fluid. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals, or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The EPA has not proposed to take any action in response to the report’s findings.
Several states, including Colorado, North Dakota, Louisiana, Oklahoma, and Texas, where we own interests in oil and natural gas producing properties, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances or require the disclosure of the composition of hydraulic-fracturing fluids. For example, in Texas, the Texas Railroad Commission (“RRC”) published a final rule in October 2014 governing permitting or re-permitting of disposal wells that require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend, or terminate the permit application or existing operating permit for that well. These existing or any new legal requirements establishing seismic permitting requirements or similar restrictions on the construction or operation of disposal wells for the injection of produced water likely will result
in added costs to comply and affect our operators’ rate of production, which in turn could have a material adverse effect on our results of operations and financial position. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where our operators conduct operations, our operators may incur substantial costs to comply with these requirements, which may be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, or production activities and perhaps even be precluded from the drilling of wells.
There has been increasing public controversy regarding hydraulic fracturing with regard to increased risks of induced seismicity, the use of fracturing fluids, impacts on drinking water supplies, use of water, and the potential for impacts to surface water, groundwater, and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic-fracturing practices. If new laws or regulations are adopted that significantly restrict hydraulic fracturing, those laws could make it more difficult or costly for our operators to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities on our properties could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, and also to attendant permitting delays and potential increases in costs. Legislative changes could cause operators to incur substantial compliance costs. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.
Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.
Our credit facility limits the amounts we can borrow to a borrowing base amount, as determined by the lenders at their sole discretion based on their valuation of our proved reserves and their internal criteria. The borrowing base is redetermined at least semi-annually, and the available borrowing amount could be further decreased as a result of such redeterminations. Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, declines in reserves, lending requirements, or regulations or certain other circumstances. As of December 31, 2016, we had outstanding borrowings of $316.0 million and the aggregate maximum credit amounts of the lenders were $1.0 billion. Our borrowing base determined by the lenders under our credit facility in October 2016 is $500.0 million and the next semi-annual redetermination is scheduled for April 2017. A future decrease in our borrowing base could be substantial and could be to a level below our then-outstanding borrowings. Outstanding borrowings in excess of the borrowing base are required to be repaid in five equal monthly payments, or we are required to pledge other oil and natural gas properties as additional collateral, within 30 days following notice from the administrative agent of the new or adjusted borrowing base. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our credit facility, or sell assets, debt, or common units. We may not be able to obtain such financing or complete such transactions on terms acceptable to us or at all. Failure to make the required repayment could result in a default under our credit facility, which could materially adversely affect our business, financial condition, results of operations, and distributions to our unitholders.
The operating and financial restrictions and covenants in our credit facility restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs, engage, expand, or pursue our business activities, or pay distributions. Our credit facility restricts, and any future credit facility likely will restrict, our ability to:
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make certain acquisitions and investments;
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enter into hedging arrangements;
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enter into transactions with our affiliates;
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make distributions to our unitholders; or
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enter into a merger, consolidation, or sale of assets.
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Our credit facility restricts our ability to make distributions to unitholders or to repurchase units unless after giving effect to such distribution or repurchase, there is no event of default under our credit facility and our outstanding borrowings are not in excess of our borrowing base. While we currently are not restricted by our credit facility from declaring a distribution, we may be restricted from paying a distribution in the future.
We also are required to comply with certain financial covenants and ratios under the credit facility. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, such as reduced oil and natural gas prices. If we violate any of the restrictions, covenants, ratios, or tests in our credit facility, a significant portion of our indebtedness may become immediately
due and payable, our ability to make distributions will be inhibited, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders can seek to foreclose on our assets.
The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas that our operators produce.
In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. These EPA rulemakings could adversely affect operations on our properties and restrict or delay the ability of our operators to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include gathering and boosting facilities as well as GHG emissions from completions and workovers of hydraulically fractured wells. Also, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified, or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storage activities. The BLM finalized similar rules in November 2016 that seek to limit methane emissions from oil and natural gas development on federal and tribal lands through limitations on venting and flaring activities. However, both the U.S. House of Representatives and the Senate have introduced resolutions seeking to repeal the BLM methane rules under the Congressional Review Act and future implementation of the BLM methane rules is uncertain. In any event, the BLM and the EPA methane rules have substantial similarities with respect to pollution control equipment and “LDAR” requirements. These rules could result in increased compliance costs for our operators and require them to make expenditures to purchase pollution control equipment and hire additional personnel to assist with complying with LDAR requirements, such as increased frequency of inspections and repairs for certain processes and equipment. Consequently, these and other regulations related to controlling GHG emissions could have an adverse impact on our business and results of operations.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation, a number of state and regional cap and trade programs have emerged. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas produced from our properties and lower the value of our reserves. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any of these effects were to occur, they could have a material adverse effect on our properties and operations.
Operating hazards and uninsured risks may result in substantial losses to us or our operators, and any losses could adversely affect our results of operations and cash distributions to unitholders.
We may be secondarily liable for damage to the environment caused by our operators. The operations of our operators will be subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses, and environmental hazards such as oil spills, natural gas leaks and ruptures, or discharges of toxic gases. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage, or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to our operators due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations, and repairs required to resume operations.
In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations, or cash distributions to unitholders. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.
We may not have coverage if we are unaware of a sudden and accidental pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We do not have, and do not intend to obtain, coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure our unitholders that the insurance coverage will be adequate to cover claims that may arise or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations, and cash distributions to unitholders.
Title to the properties in which we have an interest may be impaired by title defects.
No assurance can be given that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
Cyber attacks could significantly affect us.
Cyber attacks on businesses have escalated in recent years. We rely on electronic systems and networks to control and manage our business and have multiple layers of security to mitigate risks of cyber attack. If, however, we were to experience an attack and our security measures failed, the potential consequences to our businesses and the communities in which we operate could be significant.
Risks Inherent in an Investment in Us
We expect to distribute a substantial majority of the cash we generate from operations each quarter, which could limit our ability to grow and make acquisitions.
We expect to distribute a substantial majority of the cash we generate from operations each quarter. As a result, we will have limited cash generated from operations to reinvest in our business or to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. If we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.
If we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. Other than limitations restricting our ability to issue units ranking senior or on parity with our preferred units, there are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units with respect to distributions. The incurrence of additional commercial borrowings or other debt to finance our growth would result in increased interest expense and required principal repayments, which, in turn, may reduce the cash that we have available to distribute to our unitholders. Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy.”
The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our preferred units are outstanding.
Our partnership agreement generally provides that, during the subordination period (as defined in our partnership agreement), we will pay any distributions each quarter as follows: (i) first, to the holders of preferred units in an amount of approximately $25.00 per preferred unit, (ii) second, to the holders of common units, until each common unit has received the applicable minimum quarterly distribution plus any arrearages from prior quarters, and (iii) third, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution. If the distributions to our common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excess amounts will be distributed pro rata on the common and subordinated units as if they were a single class. The preferred units have a right to further participate (on an as-converted basis) in quarterly distributions in excess of the quarterly preferred distribution
amount under certain circumstances that we do not expect to occur. Even if those additional distributions do occur, considering that the outstanding preferred units are convertible into only a relatively small number of our total outstanding common and subordinated units, we believe these additional distributions payable under those circumstances would not materially adversely affect the per unit distribution rate we would otherwise pay on our common and subordinated units. Our minimum quarterly distribution is $1.15 per common and subordinated unit on an annualized basis (or $0.26875 per unit on a quarterly basis) for the four quarters ending March 31, 2017. The minimum quarterly distribution will be $1.25 per common and subordinated unit on an annualized basis (or $0.3125 per unit on a quarterly basis) for the four quarters ending March 31, 2018. We expect that we will distribute a substantial majority of the cash we generate from operations each quarter. However, the board of directors of our general partner could elect not to pay distributions for one or more quarters or at all. Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy.”
Our partnership agreement does not require us to pay any distributions at all on our common units. Accordingly, investors are cautioned not to place undue reliance on the permanence of any distribution policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner. If we make distributions, our preferred unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our preferred units are outstanding. Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy—Preferred Units.”
Our minimum quarterly distribution provides the common unitholders a specified priority right to distributions over the subordinated unitholders if we pay distributions. It does not provide the common unitholders the right to require payment of any distributions.
Our partnership agreement does not require us to pay any distributions on our common and subordinated units. The provision providing for a minimum quarterly distribution merely provides the common unitholders with a specified priority right to distributions before the subordinated unitholders receive distributions, if distributions are made with respect to the common and subordinated units.
Our partnership agreement eliminates the fiduciary duties that might otherwise be owed to the partnership and its partners by our general partner and its directors and executive officers under Delaware law.
Our partnership agreement contains provisions that eliminate the fiduciary duties that might otherwise be owed by our general partner and its directors and executive officers. For example, our partnership agreement provides that our general partner and its directors and executive officers have no duties to the partnership or its partners except as expressly set forth in the partnership agreement. In place of default fiduciary duties, our partnership agreement imposes a contractual standard requiring our general partner and its directors and executive officers to act in good faith, meaning they cannot cause the general partner to take an action that they subjectively believe is adverse to our interests. Such contractual standards allow our general partner and its directors and executive officers to manage and operate our business with greater flexibility and to subject the actions and determinations of our general partner and its directors and executive officers to lesser legal or judicial scrutiny than would be the case if state law fiduciary standards were applicable.
Our partnership agreement restricts the situations in which remedies may be available to our unitholders for actions taken that might constitute breaches of duty under applicable Delaware law and breaches of the contractual obligations in our partnership agreement.
Our partnership agreement restricts the potential liability of our general partner and its directors and executive officers to our unitholders. For example, our partnership agreement provides that our general partner and its directors and executive officers will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in willful misconduct or fraud or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful.
Unitholders are bound by the provisions of our partnership agreement, including the provisions described above.
Our partnership agreement restricts the voting rights of unitholders owning 15% or more of our units, subject to certain exceptions.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding, other than the limited partners in BSMC prior to the IPO, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, may not vote on any matter.
Actions taken by our general partner may affect the amount of cash generated from operations that is available for distribution to unitholders or accelerate the right to convert subordinated units.
The amount of cash generated from operations available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:
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amount and timing of asset purchases and sales;
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entry into and repayment of current and future indebtedness;
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issuance of additional units; and
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the creation, reduction, or increase of reserves in any quarter.
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In addition, borrowings by us do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:
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enabling holders of subordinated units to receive distributions; or
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hastening the expiration of the subordination period.
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In addition, our general partner may use an initial amount, equal to $137.6 million, which would not otherwise constitute cash generated from operations, in order to permit the payment of distributions on subordinated units. All of these actions may affect the amount of cash distributed to our unitholders and may facilitate the conversion of subordinated units into common units.
For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make such distribution on all outstanding units.
We have a call right that may require common unitholders to sell their common units at an undesirable time or price.
If at any point in time prior to the end of the subordination period we have acquired more than 80% of the total number of common units outstanding, we have the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by us or any of our affiliates for common units during the 90-day period preceding the date such notice is first mailed. This limited call right is not exercisable as long as any of our preferred units are outstanding, or at any time after the subordination period has ended.
Unitholders may have liability to repay distributions.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Increases in interest rates may cause the market price of our common units to decline.
An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular, for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other investment opportunities may cause the trading price of our common units to decline.
We may issue additional common units and other equity interests without common and subordinated unitholder approval, which would dilute holders of common and subordinated units. However, our partnership agreement does not authorize us to issue units ranking senior to or at parity with our preferred units without preferred unitholder approval.
Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote of the unitholders other than, in certain instances, approval of holders of our preferred units. Our issuance of additional common units or other equity interests of equal or senior rank will have the following effects:
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the proportionate ownership interest of common and subordinated unitholders in us immediately prior to the issuance will decrease;
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the amount of cash distributions on each common and subordinated unit may decrease;
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the ratio of our taxable income to distributions may increase;
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the relative voting strength of each previously outstanding common and subordinated unit may be diminished; and
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the market price of the common units may decline.
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However, our partnership agreement does not authorize us to issue securities having preferences or rights with priority over or on a parity with the preferred units with respect to rights to share in distributions, redemption obligations, or redemption rights without preferred unitholder approval.
The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets.
As of December 31, 2016, we had 95,720,686 common units and 95,164,204 subordinated units outstanding. All of the subordinated units could convert into common units on no more than a one-to-one basis at the end of the subordination period. Sales by holders of a substantial number of our common units in the public markets, or the perception that these sales might occur, could have a material adverse effect on the price of our common units or impair our ability to obtain capital through an offering of equity securities.
The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.
The market price of our common units may be influenced by many factors, some of which are beyond our control, including those described elsewhere in these risk factors.
We have and will continue to incur increased costs as a result of being a publicly traded partnership.
As a publicly traded partnership, we have and will continue to incur significant legal, accounting, and other expenses that we did not incur prior to the IPO. In addition, the Sarbanes-Oxley Act, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to maintain various corporate governance practices that further increase our costs. Before we are able to make distributions to our unitholders, we must first pay or reserve for our expenses, including the costs of being a publicly traded partnership. As a result, the amount of cash we have available to distribute to our unitholders will be affected by the costs associated with being a publicly traded partnership.
Following the IPO, we became subject to the public reporting requirements of the Securities Exchange Act of 1934 (the “Exchange Act”). These requirements have increased our legal and financial compliance costs.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and operate successfully as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future, or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.
The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. In addition, because we are a publicly traded partnership, the NYSE does not require us to obtain unitholder approval prior to certain unit issuances. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements.
Our partnership agreement includes exclusive forum, venue, and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions, or proceedings, and submitting to the exclusive jurisdiction of Delaware courts.
Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue, and jurisdiction provisions designating Delaware courts as the exclusive venue for all claims, suits, actions, or proceedings arising out of or relating in any way to the partnership agreement, brought in a derivative manner on behalf of the partnership, asserting a claim of breach of a fiduciary or other duty owed by any director, officer, or other employee of the partnership or the general partner, or owed by the general partner to the partnership or the partners, asserting a claim arising pursuant to any provision of the Delaware Act, or asserting a claim governed by the internal affairs doctrine. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions, or proceedings and submitting to the exclusive jurisdiction of Delaware courts. If a dispute were to arise between a limited partner and us or our officers, directors, or employees, the limited partner may be required to pursue its legal remedies in Delaware, which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment.
If a unitholder is not an Eligible Holder, the common units of such unitholder may be subject to redemption.
We have adopted certain requirements regarding those investors who may own our units. Eligible Holders are limited partners (a) whose, or whose owners’, federal income tax status does not have or is not reasonably likely to have a material adverse effect on the rates chargeable by us to customers and (b) whose ownership could not result in our loss of ownership in any material part of our assets, as determined by our general partner with the advice of counsel. If an investor is not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, units by such investor may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash distributions to unitholders could be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, cash distributions to our unitholders would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, and other forms of taxation. Imposition of any of those taxes may substantially reduce the cash distributions to our unitholders. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash generated from operations and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly applied on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative, or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider similar substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for federal income tax purposes.
In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations apply to taxable years beginning on or after January 19, 2017 and generally treat income from passive mineral interests (such as
royalty income) as qualifying income. However, there can be no assurance that there will not be further changes to the Treasury Department's interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.
Any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted or adopted. Any such changes could negatively impact the value of an investment in our common units.
Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction.
In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation including changes to cost recovery rules and to the deductibility of interest expense may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on the Company’s financial position, results of operations and cash flows.
If the IRS were to contest the federal income tax positions we take, it may adversely affect the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely affect the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any appliable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties or interest, our cash available for distribution to our unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.
Even if you, as a unitholder, do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.
You will be required to pay federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or not you receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale and our cash
available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for distribution. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.
Tax gain or loss on disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell your units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
A substantial portion of the amount realized from the sale of your units, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture. Thus, you may recognize both ordinary income and capital loss from the sale of your units if the amount realized on a sale of your units is less than your adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which you sell your units, you may recognize ordinary income from our allocations of income and gain to you prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, a portion of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income and may be taxable to them. Distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person may be required to file United States federal tax returns and pay tax on their share of our taxable income if it is treated as effectively connected income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.
We treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of our common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.
We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss, and deduction among our unitholders.
We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.
A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and could recognize gain or loss from the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from this disposition. Moreover, during the period of the loan, any of our income, gain, loss, or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that includes our termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K‑1 to unitholders for the two short tax periods included in the year in which the termination occurs.
You, as a unitholder, may be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.
In addition to federal income taxes, you likely will be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. We will initially own assets and conduct business in several states, many of which impose a personal income tax and also impose income taxes on corporations and other entities. You may be required to file state and local income tax returns and pay state and local income taxes in these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state, and local tax returns.