10-K 1 bsm10-kdoc.htm 10-K Document


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
For the transition period _______________ to _______________
Commission file number 001-37362
Black Stone Minerals, L.P.
(Exact Name of Registrant As Specified in Its Charter)
Delaware
 
47-1846692
(State or Other Jurisdiction of
Incorporation or Organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
1001 Fannin Street, Suite 2020
Houston, Texas
 
77002
(Address of Principal Executive Offices)
 
(Zip Code)
Registrant’s telephone number, including area code:  (713) 445-3200
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Units Representing Limited Partner Interests
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x  No ¨  
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨   No  x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One):
Large Accelerated Filer
 
x
 
 
Accelerated Filer
 
¨
 
 
 
 
 
 
 
Non-Accelerated Filer
 
¨
(Do not check if a smaller reporting company)
 
Smaller Reporting Company
 
¨
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨   No  x

The aggregate market value of the common units held by non-affiliates was $1,064,853,317 on June 30, 2016, the last business day of the registrant’s most recently completed second fiscal quarter, based on a closing price of $15.50 per unit as reported by the New York Stock Exchange on such date. As of February 22, 2017, 97,113,310 common units, 95,149,984 subordinated units, and 52,691 preferred units of the registrant were outstanding.
Documents Incorporated by Reference: Certain information called for in Items 10, 11, 12, 13, and 14 of Part III are incorporated by reference from the registrant’s definitive proxy statement for the annual meeting of unitholders to be held on June 8, 2017.
 




BLACK STONE MINERALS, L.P.
TABLE OF CONTENTS
 
 
 
PAGE
 
 
 
 

ii

GLOSSARY OF TERMS

The following list includes a description of the meanings of some of the oil and gas industry terms used in this Annual Report on Form 10-K (“Annual Report”).
Basin. A large depression on the earth’s surface in which sediments accumulate.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.
Bbl/d. Bbl per day.
Bcf. One billion cubic feet of natural gas.
Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. This “Btu-equivalent” conversion metric is based on an approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.
Boe/d. Boe per day.
British Thermal Unit (Btu). The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion. The process of treating a drilling well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Crude oil. Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Delaware Act. Delaware Revised Uniform Limited Partnership Act.
Delay rental. Payment made to the lessor under a non-producing oil and natural gas lease at the end of each year to defer a drilling obligation and continue the lease for another year during its primary term.
Deterministic method. The method of estimating reserves or resources under which a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Development costs. Capital costs incurred in the acquisition, exploitation, and exploration of proved oil and natural gas reserves.
Development well. A well drilled within the proved area of an oil and natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry hole or dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
Electrical log. An analysis that provides information on porosity, hydraulic conductivity, and fluid content of formations drilled in fluid-filled boreholes.
Exploitation. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

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GLOSSARY OF TERMS

Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
Extension well. A well drilled to extend the limits of a known reservoir.
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Formation. A layer of rock which has distinct characteristics that differs from nearby rock.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
Hydraulic fracturing. A process used to stimulate production of hydrocarbons. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.
Lease bonus. Usually a one-time payment made to a mineral owner as consideration for the execution of an oil and natural gas lease.
Lease operating expense. All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, supplies, repairs, maintenance, allocated overhead charges, workover costs, insurance, and other expenses incidental to production, but exclude lease acquisition or drilling or completion costs.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
MBoe. One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil.
MBoe/d. MBoe per day.
Mcf. Thousand cubic feet of natural gas.
Mineral interests. Real-property interests that 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.
MMBtu. Million British Thermal Units.
MMcf. Million cubic feet of natural gas.
Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, respectively.
Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty, overriding royalty, and other non-cost-bearing interests.
Natural gas. A combination of light hydrocarbons that, in average pressure and temperature conditions, is found in a gaseous state. In nature, it is found in underground accumulations, and may potentially be dissolved in oil or may also be found in its gaseous state.
NGLs. Natural gas liquids.
Nonparticipating royalty interest (NPRI). A type of non-cost-bearing royalty interest, which is carved out of the mineral interest and represents 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.
NYMEX. New York Mercantile Exchange.

iv

GLOSSARY OF TERMS

Oil. Crude oil and condensate.
Oil and natural gas properties. Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
Operator. The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
Overriding royalty interest (ORRI). A fractional, undivided interest or right of participation in the oil or natural gas, or in the proceeds from the sale of the oil or gas, produced from a specified tract or tracts, which are limited in duration to the terms of an existing lease and which are not subject to any portion of the expense of development, operation, or maintenance.
PDP. Proved developed producing, used to characterize reserves.
Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism, and hydrocarbon type.
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Pooling. The majority of our producing acreage is pooled with third-party acreage. Pooling refers to an operator’s consolidation of multiple adjacent leased tracts, which may be covered by multiple leases with multiple lessors, in order to maximize drilling efficiency or to comply with state mandated well spacing requirements. Pooling dilutes our royalty in a given well or unit, but it also increases both the acreage footprint and the number of wells in which we have an economic interest. To estimate our total potential drilling locations in a given play, we include third-party acreage that is pooled with our acreage.
Production Costs. The production or operational costs incurred while extracting and producing, storing, and transporting oil and/or natural gas. Typical of these costs are wages for workers, facilities lease costs, equipment maintenance, logistical support, applicable taxes, and insurance.
PUD. Proved undeveloped, used to characterize reserves.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved developed producing reserves. Reserves expected to be recovered from existing completion intervals in existing wells.
Proved reserves. The estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Reliable technology. A grouping of one or more technologies (including computation 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.
Reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market, and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). 

v

GLOSSARY OF TERMS

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Resource play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic, and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism, and hydrocarbon type.
Royalty interest. An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.
Seismic data. Seismic data is used by scientists to interpret the composition, fluid content, extent, and geometry of rocks in the subsurface. Seismic data is acquired by transmitting a signal from an energy source, such as dynamite or water, into the earth. The energy so transmitted is subsequently reflected beneath the earth’s surface and a receiver is used to collect and record these reflections.
Shale. A fine grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.
Spacing. The distance between wells producing from the same reservoir and is often established by regulatory agencies.
Standardized measure. The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.
Tight formation. A formation with low permeability that produces natural gas with low flow rates for long periods of time.
Trend. A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical, or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working interest. An operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property, and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
Workover. Operations on a producing well to restore or increase production.
WTI. West Texas Intermediate oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute (“API”) gravity between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for the other crude oils.
 
 
 

vi




CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Annual Report may constitute “forward-looking statements.”  The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature.  These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us.  While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate.  All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions.  Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections.  Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:
our ability to execute our business strategies;
the volatility of realized oil and natural gas prices;
the level of production on our properties;
regional supply and demand factors, delays, or interruptions of production;
our ability to replace our oil and natural gas reserves;
our ability to identify, complete, and integrate acquisitions;
general economic, business, or industry conditions;
competition in the oil and natural gas industry;
the ability of our operators to obtain capital or financing needed for development and exploration operations;
title defects in the properties in which we invest;
the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;
restrictions on the use of water;
the availability of transportation facilities;
the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
federal and state legislative and regulatory initiatives relating to hydraulic fracturing;
future operating results;
future cash flows and liquidity, including our ability to generate sufficient cash to pay quarterly distributions;
exploration and development drilling prospects, inventories, projects, and programs;
operating hazards faced by our operators;
the ability of our operators to keep pace with technological advancements; and
certain factors discussed elsewhere in this Annual Report.
For additional information regarding known material factors that could cause our actual results to differ from our projected results, please read Part I, Item 1A. “Risk Factors.”
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events, or otherwise.


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PART I


Unless the context clearly indicates otherwise, references in this Annual Report on Form 10-K to “BSMC,” “Black Stone Minerals, L.P. Predecessor,” or “our predecessor,” refer to Black Stone Minerals Company, L.P. and its subsidiaries for time periods prior to the initial public offering of Black Stone Minerals, L.P. on May 6, 2015 (the “IPO”), and references to “BSM,” “Black Stone,” “we,” “our,” “us,” “the Partnership,” or like terms refer to Black Stone Minerals, L.P. and its subsidiaries for time periods subsequent to the IPO.
 
 
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.
 

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 a2015map.jpg
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:
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
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.
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

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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.

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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:
 
 
 
Acreage as of December 31, 2016
 
Average Daily
Production (Boe/d)
For the Year Ended
December 31, 2016
 
 
Mineral and Royalty Interests
 
Working Interests1
 
USGS Petroleum Province2
 
Mineral Interests
 
NPRIs
 
ORRIs
 
Gross
 
Net
 
Louisiana-Mississippi Salt Basins
 
5,446,455

 
162,199

 
18,846

 
49,170

 
6,203

 
5,053

Western Gulf (onshore)
 
1,597,765

 
213,111

 
98,752

 
116,134

 
17,394

 
6,191

Williston Basin
 
1,323,172

 
62,133

 
31,884

 
54,734

 
7,741

 
4,061

Palo Duro Basin
 
1,016,847

 
22,791

 
1,120

 

 

 
24

Permian Basin
 
1,016,197

 
587,167

 
177,275

 
8,113

 
4,731

 
1,441

Anadarko Basin
 
550,740

 
13,723

 
180,157

 
31,313

 
21,294

 
1,909

Appalachian Basin
 
490,274

 
416

 
14,836

 

 

 
874

East Texas Basin
 
456,110

 
44,429

 
30,640

 
151,811

 
51,589

 
6,906

Arkoma Basin
 
338,767

 
9,087

 
37,957

 
9,045

 
2,333

 
1,614

Bend Arch-Fort Worth Basin
 
144,246

 
55,205

 
40,249

 
53,606

 
13,585

 
427

Southwestern Wyoming
 
22,338

 

 
75,577

 
15,336

 
2,477

 
454

Other
 
3,113,014

 
310,992

 
798,542

 
39,408

 
8,924

 
2,729

Total
 
15,515,925

 
1,481,253

 
1,505,835

 
528,670

 
136,271

 
31,683



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.
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.
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.
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.
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.  
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.
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.
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.
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. 
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.
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.
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.






6


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:
 
 
 
 
 
 
 
 
Average Daily Production (Boe/d)
 
 
As of December 31, 2016
 
For the Year Ended December 31,
USGS Petroleum Province1
 
Acres
 
Average
Ownership
Interest2
 
Average
Ownership
Leased3
 
2016
 
2015
 
2014
Louisiana-Mississippi Salt Basins
 
5,446,455

 
53.4
%
 
9.6
%
 
3,415

 
3,384

 
4,061

Western Gulf (onshore)
 
1,597,765

 
55.0
%
 
34.7
%
 
4,526

 
5,021

 
4,099

Williston Basin
 
1,323,172

 
14.8
%
 
35.4
%
 
2,534

 
2,430

 
1,989

Palo Duro Basin
 
1,016,847

 
46.5
%
 
7.2
%
 
24

 
23

 
16

Permian Basin
 
1,016,197

 
14.0
%
 
66.6
%
 
1,035

 
585

 
566

Black Warrior Basin
 
592,968

 
54.6
%
 
2.3
%
 

 
39

 
41

Eastern Great Basin
 
567,749

 
96.7
%
 
0.1
%
 
39

 

 

Anadarko Basin
 
550,740

 
32.7
%
 
59.6
%
 
673

 
959

 
790

Appalachian Basin
 
490,274

 
39.8
%
 
22.1
%
 
163

 
80

 
89

East Texas Basin
 
456,110

 
52.7
%
 
39.4
%
 
1,854

 
884

 
793

Arkoma Basin
 
338,767

 
53.7
%
 
27.6
%
 
1,302

 
1,458

 
1,646

Western Great Basin
 
338,303

 
90.5
%
 
 –

 

 

 

Piedmont
 
179,879

 
67.8
%
 
 –

 

 

 

North-Central Montana
 
171,026

 
13.7
%
 
27.8
%
 
9

 
4

 
7

Atlantic Coastal Plain
 
164,670

 
12.8
%
 
28.8
%
 
199

 

 

Bend Arch-Fort Worth Basin
 
144,246

 
20.5
%
 
33.3
%
 

 
392

 
252

Cherokee Platform
 
111,027

 
13.8
%
 
32.4
%
 
34

 
41

 
46

Florida Peninsula
 
90,744

 
12.1
%
 
47.6
%
 
2

 

 

Illinois Basin
 
80,864

 
53.1
%
 
8.0
%
 
3

 
2

 
1

Powder River Basin
 
67,055

 
11.3
%
 
12.3
%
 

 
56

 
3

Other
 
771,067

 
32.1
%
 
20.4
%
 
1,295

 
301

 
317

Total
 
15,515,925

 
45.7
%
 
22.0
%
 
17,107

 
15,659

 
14,716


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.
 






7





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,
USGS Petroleum Province1
 
Acres
 
Average
Royalty
Interest2
 
Average
Percent
Leased3
 
2016
 
2015
 
2014
Permian Basin
 
587,167

 
2.1
%
 
47.5
%
 
19

 
31

 
11

Western Gulf (onshore)
 
213,111

 
4.6
%
 
46.0
%
 
14

 
10

 
14

Louisiana-Mississippi Salt Basins
 
162,199

 
4.9
%
 
48.3
%
 
1

 

 
 <1

North-Central Montana
 
134,559

 
3.0
%
 
9.3
%
 

 

 

Marathon Thrust Belt
 
117,442

 
4.9
%
 
1.6
%
 

 

 

Williston Basin
 
62,133

 
2.6
%
 
33.0
%
 
92

 
106

 
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.





8




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 Province1
 
Acres
 
Average
Royalty
Interest2
 
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.
 







9




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 Province1
 
Gross Acres2
 
Net Acres2
 
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.
 
















10





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 Province1
 
Gross Well Count2
 
USGS Petroleum Province1
 
Gross Well Count2
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.
 








11




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, 20161
 
 
Mineral and Royalty Interests
 
Working Interests
Resource Play2
 
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.
 








12




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 Play1
 
Acres
 
Average
Ownership
Interest2
 
Average
Ownership
Leased3
 
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.  

 






13




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 Play1
 
Acres
 
Average
Royalty
Interest2
 
Average
Percent
Leased3
 
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.  
 








14




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 Play1
 
Acres
 
Average
Royalty
Interest2
 
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.  
 










15




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 Play1
 
Gross Acres2
 
Net Acres2
 
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

16


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.







17




Summary of Estimated Proved Reserves
The following table presents our estimated proved oil and natural gas reserves:
 
 
As of
December 31, 20161
As of
December 31, 2015
 
(Unaudited)
(Unaudited)
Estimated proved developed reserves2:
 
 
Oil (MBbls)
18,150

15,497

Natural gas (MMcf)
223,057

174,555

Total (MBoe)
55,327

44,590

Estimated proved undeveloped reserves3:
 
 
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.”

18


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.

19


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 Prices2:
 
 

 
 

 
 

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.







20


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

 













21


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