10-K 1 bsm10-kdocx12312017.htm 10-K Document


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth 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
¨
 
 
 
 
 
 
Emerging Growth Company
¨

 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
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 $1,197,800,850 on June 30, 2017, the last business day of the registrant’s most recently completed second fiscal quarter, based on a closing price of $15.76 per unit as reported by the New York Stock Exchange on such date. As of February 20, 2018, 104,258,290 common units, 95,388,424 subordinated units, 24,803 Series A redeemable preferred units, and 14,711,219 Series B cumulative convertible 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.
 




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.
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.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

iii

GLOSSARY OF TERMS

Extension well. A well drilled to extend the limits of a known reservoir.
Farmout agreement. An agreement with a working interest owner, called the "farmor," whereby the farmor agrees to assign some or all of the working interest to another party, called the "farmee," in exchange for certain contractually agreed services with respect to such acreage or for payment for drilling operations on the acreage.
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 other nearby rock.
Gross acres or gross wells. The total acres or wells, as the case may be, in which an 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.
Log. An analysis that provides information on porosity, hydraulic conductivity, and fluid content of formations drilled in fluid-filled boreholes.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
MBoe. One thousand Boe.
MBoe/d. MBoe per day.
Mcf. One 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 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.

iv

GLOSSARY OF TERMS

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.
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.

v

GLOSSARY OF TERMS

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). 
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, 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 Securities and Exchange Commission (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 been generally 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% by weight 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;
the overall supply and demand for oil and natural gas, and 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 for hydraulic fracturing;
the availability of pipeline capacity and 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.


1

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 and managers of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing 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 16.8 million acres, with an average 43.4% ownership interest in that acreage. We also own NPRIs in 1.9 million acres and ORRIs in 2.1 million acres. These non-cost-bearing interests, which we refer to collectively as our “mineral and royalty interests,” include ownership in approximately 55,728 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 Haynesville/Bossier Shales in East Texas/Western Louisiana, the Wolfcamp/Spraberry/Bone Spring in the Permian Basin, the Bakken/Three Forks in the Williston Basin, the Eagle Ford Shale in South Texas, the Niobrara/Codell Shales in the DJ Basin, 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, the long-lived, non-cost-bearing nature of our mineral and royalty interests, and our active management expose 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.


2


Our Assets
As of December 31, 2017, our total estimated proved oil and natural gas reserves were 67,945 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, 2017, approximately 83.5% were proved developed reserves (approximately 82.4% proved developed producing and 1.1% proved developed non-producing) and approximately 16.5% were proved undeveloped reserves. At December 31, 2017, our estimated proved reserves were 26.3% oil and 73.7% 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.
 map.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, or by making an extension payment. 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

3


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 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. Working interest production represented 40.0% of our total production volumes during the year ended December 31, 2017. As of December 31, 2017, we owned non-operated working interests in 9,688 gross (352 net) wells.
Our 2018 drilling capital expenditure budget associated with our working-interest participation program is expected to range between $15 million and $25 million. Approximately 99% of our 2018 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. In 2018, we also expect to spend an additional $10 million to $12 million to drill two 100% working interest exploratory wells to evaluate a Lower Wilcox prospect in East Texas.

Farmout Agreements
On February 21, 2017, we announced that we entered into a farmout agreement with Canaan Resource Partners ("Canaan", and such farmout, the "Canaan Farmout"), which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc. We have an approximate 50% working interest in the acreage. A total of 18 wells are anticipated to be drilled over an initial phase, beginning with wells spud after January 1, 2017. As of December 31, 2017, 10 wells had been drilled during the initial phase. At its option, Canaan may participate in two additional phases with each phase continuing for the lesser of 2 years or until 20 wells have been drilled. During the first three phases of the agreement, Canaan will commit on a phase-by-phase basis and fund 80% of our drilling and completion costs and will be assigned 80% of our working interests in such wells (40% working interest on an 8/8ths basis). After the third phase, Canaan can earn 40% of our working interest (20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40% of our costs for those wells on a well-by-well basis. We will receive a base ORRI before payout and an additional ORRI after payout on all wells drilled under the agreement. The Canaan Farmout is anticipated to reduce our future capital expenditures by approximately $40 to $50 million annually during the term of the agreement.
On November 21, 2017, we entered into a farmout agreement with a portfolio company of Tailwater Capital, LLC, Pivotal Petroleum Partners (“Pivotal”), that covers substantially all of our remaining working interests under active development in the Shelby Trough area of East Texas targeting the Haynesville and Bossier shale acreage after giving effect to the Canaan Farmout (discussed above) over the next eight years. In wells operated by XTO Energy Inc. in San Augustine County, Texas, Pivotal will earn our remaining approximate 20% working interest (10% working interest on an 8/8ths basis) not covered by the Canaan Farmout, as well as 100% of our working interests (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells operated by our other major operator in the area. Initially, Pivotal will be obligated to fund the development of up to 80 wells across several development areas and then will have options to continue funding our working interest across those areas for the duration of the eight year term. After the funding of a designated group of wells by Pivotal and once Pivotal achieves a specified payout for such well group, the Partnership will obtain a majority of the original working interest in the designated group of wells.
As a result of the farmout agreements with Canaan and Pivotal, we expect capital requirements associated with non-operated working interests to be minimal beyond the first quarter of 2018.

4


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 below 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 can be 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, 2017
 
Average Daily Production (Boe/d)
For the Year Ended December 31, 2017
 
 
 
Mineral and Royalty Interests
 
Working Interests1
 
USGS Petroleum Province2
 
Mineral Interests
 
NPRIs
 
ORRIs
 
Gross
 
Net
 
Louisiana-Mississippi Salt Basins
 
5,408,632

 
238,426

 
26,104

 
59,117

 
7,999

 
4,752

Western Gulf (onshore)
 
1,732,750

 
297,303

 
282,208

 
122,167

 
18,692

 
5,561

Permian Basin
 
1,647,573

 
800,654

 
185,069

 
8,113

 
5,051

 
2,820

Williston Basin
 
1,543,797

 
65,974

 
34,099

 
59,875

 
7,895

 
3,624

Palo Duro Basin
 
1,024,913

 
22,791

 
1,120

 

 

 
87

East Texas Basin
 
598,717

 
55,155

 
78,960

 
148,121

 
50,693

 
13,704

Anadarko Basin
 
577,264

 
13,723

 
280,283

 
30,939

 
21,254

 
1,652

Appalachian Basin
 
495,843

 
416

 
14,861

 

 

 
853

Arkoma Basin
 
357,394

 
9,999

 
38,109

 
9,045

 
2,333

 
1,337

Bend Arch-Fort Worth Basin
 
149,260

 
56,703

 
43,514

 
52,885

 
13,475

 
353

Southwestern Wyoming
 
22,338

 

 
77,529

 
14,056

 
2,050

 
483

Other
 
3,235,453

 
314,539

 
1,033,649

 
39,152

 
8,742

 
1,785

Total
 
16,793,934

 
1,875,683

 
2,095,505

 
543,470

 
138,184

 
37,011

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.


5


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.
Williston Basin. The Williston Basin stretches through the western half of North Dakota, the northwest part of South Dakota, and eastern Montana and includes plays such as the Bakken/Three Forks plays, where we have significant exposure through our mineral and royalty interests as well as through our working interests. We are also exposed to other well-known plays in the basin, including the Duperow, Mission Canyon, Madison, Ratcliff, Red River, and Spearfish plays.
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.  
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.
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. 
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:
 
 
As of December 31, 2017
 
Average Daily Production (Boe/d) for the Year Ended December 31,
USGS Petroleum Province1
 
Acres
 
Average Ownership Interest2
 
Average Ownership Leased3
 
2017
 
2016
 
2015
Louisiana-Mississippi Salt Basins
 
5,408,632

 
53.3
%
 
8.7
%
 
3,867

 
3,415

 
3,384

Western Gulf (onshore)
 
1,732,750

 
52.7
%
 
36.0
%
 
4,668

 
4,526

 
5,021

Permian Basin
 
1,647,573

 
11.6
%
 
79.2
%
 
2,443

 
1,035

 
585

Williston Basin
 
1,543,797

 
14.6
%
 
44.7
%
 
2,906

 
2,534

 
2,430

Palo Duro Basin
 
1,024,913

 
46.2
%
 
8.7
%
 
75

 
24

 
23

East Texas Basin
 
598,717

 
53.0
%
 
32.3
%
 
3,098

 
1,854

 
884

Black Warrior Basin
 
594,906

 
54.6
%
 
2.3
%
 
38

 

 
39

Anadarko Basin
 
577,264

 
31.7
%
 
61.8
%
 
745

 
673

 
959

Eastern Great Basin
 
567,909

 
96.7
%
 
0.1
%
 

 
39

 

Appalachian Basin
 
495,843

 
39.4
%
 
15.3
%
 
191

 
163

 
80

Arkoma Basin
 
357,394

 
52.9
%
 
31.6
%
 
1,172

 
1,302

 
1,458

Western Great Basin
 
338,303

 
90.5
%
 

 

 

 

North-Central Montana
 
182,868

 
13.5
%
 
32.5
%
 
3

 
9

 
4

Piedmont
 
179,879

 
67.8
%
 

 

 

 

Atlantic Coastal Plain
 
171,791

 
12.5
%
 
31.7
%
 

 
199

 

Bend Arch-Fort Worth Basin
 
149,260

 
20.8
%
 
34.7
%
 
198

 

 
392

Cherokee Platform
 
112,384

 
13.8
%
 
33.6
%
 
26

 
34

 
41

Florida Peninsula
 
90,744

 
12.1
%
 
47.6
%
 

 
2

 

Illinois Basin
 
80,864

 
53.1
%
 
8.0
%
 
2

 
3

 
2

Powder River Basin
 
80,239

 
11.2
%
 
26.7
%
 
6

 

 
56

Other
 
857,904

 
30.6
%
 
27.2
%
 
967

 
1,295

 
301

Total
 
16,793,934

 
43.4
%
 
26.4
%
 
20,405

 
17,107

 
15,659

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:
 
 
As of December 31, 2017
 
Average Daily Production (Boe/d) for the Year Ended December 31,
USGS Petroleum Province1
 
Acres
 
Average Royalty Interest2
 
Average Percent Leased3
 
2017
 
2016
 
2015
Permian Basin
 
800,654

 
1.9
%
 
61.6
%
 
39

 
19

 
31

Western Gulf (onshore)
 
297,303

 
3.5
%
 
61.2
%
 
7

 
14

 
10

Louisiana-Mississippi Salt Basins
 
238,426

 
4.1
%
 
64.9
%
 
4

 
1

 

North-Central Montana
 
138,027

 
3.0
%
 
11.6
%
 

 

 

Marathon Thrust Belt
 
117,442

 
4.9
%
 
1.6
%
 

 

 

Williston Basin
 
65,974

 
2.7
%
 
38.0
%
 
108

 
92

 
106

Bend Arch-Fort Worth Basin
 
56,703

 
4.1
%
 
14.4
%
 
1

 
1

 

East Texas Basin
 
55,155

 
2.6
%
 
79.9
%
 
556

 
179

 
381

Powder River Basin
 
33,467

 
6.1
%
 
7.2
%
 

 

 

Palo Duro Basin
 
22,791

 
3.8
%
 
1.7
%
 

 

 

Anadarko Basin
 
13,723

 
3.6
%
 
94.3
%
 
32

 
18

 
8

Arkoma Basin
 
9,999

 
2.4
%
 
85.3
%
 
9

 
13

 
21

Cambridge Arch-Central Kansas Uplift
 
8,903

 
5.5
%
 
83.7
%
 

 

 

Southwest Montana
 
4,367

 
6.2
%
 
7.3
%
 

 

 

Cherokee Platform
 
2,555

 
4.7
%
 
31.3
%
 

 

 

Nemaha Uplift
 
2,334

 
1.6
%
 
41.4
%
 

 

 

Montana Thrust Belt
 
2,242

 
4.1
%
 
%
 

 

 

Sedgwick Basin
 
1,850

 
2.5
%
 
82.2
%
 

 

 

Black Warrior Basin
 
1,500

 
0.3
%
 
100.0
%
 

 

 

Uinta-Piceance Basin
 
560

 
1.0
%
 
%
 

 

 

Other
 
1,708

 
5.2
%
 
29.9
%
 
169

 
180

 
185

Total
 
1,875,683

 
3.0
%
 
51.3
%
 
925

 
518

 
742

1  
The basins and regions shown in the table are consistent with USGS petroleum-province delineations.
2
Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in the basin or region. NPRIs may be denominated as a “fractional royalty,” which entitles the owner to the stated fraction of gross production, or a “fraction of royalty,” where the stated fraction is multiplied by the lease royalty. In cases where our land documentation does not specify the form of NPRI, we have assumed a fractional royalty for purposes of the average royalty interests shown above.
3
The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the basin or region.










8


ORRIs
The following table sets forth information about our ORRIs:
 
 
As of December 31, 2017
 
Average Daily Production (Boe/d) for the Year Ended December 31,
USGS Petroleum Province1
 
Acres
 
Average Royalty Interest2
 
2017
 
2016
 
2015
North-Central Montana
 
457,897

 
2.5
%
 
2

 
13

 
35

Western Gulf (onshore)
 
282,208

 
2.8
%
 
246

 
157

 
262

Anadarko Basin
 
280,283

 
3.4
%
 
188

 
200

 
232

Permian Basin
 
185,069

 
1.0
%
 
106

 
64

 
72

Uinta-Piceance Basin
 
174,701

 
2.5
%
 
21

 
24

 
37

Powder River Basin
 
120,722

 
3.8
%
 
26

 
45

 
98

East Texas Basin
 
78,960

 
6.9
%
 
97

 
96

 
81

Southwestern Wyoming
 
77,529

 
2.0
%
 
415

 
451

 
529

Michigan Basin
 
56,512

 
1.0
%
 
20

 
18

 
21

Denver Basin
 
45,608

 
4.4
%
 
156

 
117

 
83

Bend Arch-Fort Worth Basin
 
43,514

 
4.7
%
 
100

 
108

 
160

Paradox Basin
 
43,301

 
1.3
%
 
1

 

 
2

Arkoma Basin
 
38,109

 
3.0
%
 
20

 
23

 
29

San Juan Basin
 
37,644

 
1.1
%
 
4

 
6

 
3

Williston Basin
 
34,099

 
2.1
%
 
62

 
59

 
76

Louisiana-Mississippi Salt Basins
 
26,104

 
3.8
%
 
405

 
705

 
1,185

Northern Alaska
 
24,214

 
3.5
%
 
28

 
28

 
32

Wind River Basin
 
8,528

 
1.1
%
 
34

 
27

 
33

Cambridge Arch-Central Kansas Uplift
 
17,469

 
4.9
%
 
3

 
3

 
5

Appalachian Basin
 
14,861

 
2.5
%
 
706

 
693

 

Other
 
48,173

 
1.4
%
 
91

 
156

 
911

Total
 
2,095,505

 
2.8
%
 
2,731

 
2,993

 
3,886

1  
The basins and regions shown in the table are consistent with USGS petroleum-province delineations.
2  
Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in the basin or region.
 









9


Working Interests
The following table sets forth information about our non-operated working interests:
 
 
As of December 31, 2017
 
Average Daily Production (Boe/d) for the Year Ended December 31,
USGS Petroleum Province1
 
Gross Acres2
 
Net Acres2
 
2017
 
2016
 
2015
East Texas Basin
 
148,121

 
50,693

 
9,803

 
4,776

 
2,341

Western Gulf (onshore)
 
122,167

 
18,692

 
640

 
1,494

 
1,234

Williston Basin
 
59,875

 
7,895

 
548

 
1,377

 
1,425

Louisiana-Mississippi Salt Basins
 
59,117

 
7,999

 
476

 
932

 
1,007

Bend Arch-Fort Worth Basin
 
52,885

 
13,475

 
54

 
118

 
108

Anadarko Basin
 
30,939

 
21,254

 
687

 
1,018

 
1,205

Southwestern Wyoming
 
14,056

 
2,050

 
24

 
11

 
1

Michigan Basin
 
13,287

 
1,330

 

 
6

 
6

Powder River Basin
 
12,936

 
3,382

 
68

 
103

 
169

Arkoma Basin
 
9,045

 
2,333

 
136

 
277

 
341

Permian Basin
 
8,113

 
5,051

 
232

 
323

 
214

Denver Basin
 
4,923

 
1,040

 
133

 
130

 
5

Paradox Basin
 
2,602

 
1,281

 
2

 
4

 
5

North-Central Montana
 
2,080

 
605

 

 
1

 
1

Uinta-Piceance Basin
 
1,005

 
482

 
50

 
68

 

San Juan Basin
 
960

 
334

 

 
15

 
11

Wind River Basin
 
440

 
43

 

 

 

Southern Oklahoma
 
390

 
92

 
97

 
132

 
174

Cherokee Platform
 
328

 
137

 

 
1

 
5

Illinois Basin
 
200

 
16

 

 

 

Other
 
1

 

 

 
279

 
128

Total
 
543,470

 
138,184

 
12,950

 
11,065

 
8,380

1  
The basins and regions shown in the table are consistent with USGS petroleum-province delineations.
2  
Excludes acreage that is not quantifiable due to incomplete seller records.
 



















10


Wells
The following tables set forth information about our mineral-and-royalty-interest and working-interest wells as of December 31, 2017:
Mineral and Royalty Interests
 
Working Interests
USGS Petroleum Province1
 
Gross Well Count2
 
USGS Petroleum Province1
 
Gross Well Count2
Permian Basin
 
23,685

 
Anadarko Basin
 
2,898

Anadarko Basin
 
4,068

 
Uinta-Piceance Basin
 
1,378

East Texas Basin
 
3,992

 
Permian Basin
 
908

Williston Basin
 
3,561

 
East Texas Basin
 
907

Louisiana-Mississippi Salt Basin
 
3,504

 
Arkoma Basin
 
751

Western Gulf (onshore)
 
3,494

 
Western Gulf (onshore)
 
640

Arkoma Basin
 
2,009

 
Louisiana-Mississippi Salt Basin
 
546

Uinta-Piceance Basin
 
1,750

 
Williston Basin
 
542

Bend Arch-Fort Worth Basin
 
1,230

 
Southern Oklahoma
 
389

Michigan Basin
 
924

 
Bend Arch-Fort Worth Basin
 
228

Appalachian Basin
 
846

 
Appalachian Basin
 
189

Southwestern Wyoming
 
783

 
Nemaha Uplift
 
104

Denver Basin
 
707

 
Powder River Basin
 
63

Cherokee Platform
 
642

 
Michigan Basin
 
62

San Juan Basin
 
627

 
Denver Basin
 
21

North-Central Montana
 
605

 
Cherokee Platform
 
16

Powder River Basin
 
490

 
Palo Duro Basin
 
11

Wyoming Thrust Belt
 
391

 
North-Central Montana
 
10

Southern Oklahoma
 
369

 
Paradox Basin
 
8

San Joaquin Basin
 
363

 
Black Warrior Basin
 
5

Other
 
1,688

 
Other
 
12

Total
 
55,728

 
Total
 
9,688

1  
The basins and regions shown in the table are consistent with USGS petroleum-province delineations.
2
We own both mineral and royalty interests and working interests in 3,973 of the wells shown in each column above.
 










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 can be 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 70% of our aggregate production for the year ended December 31, 2017.
 
 
Acreage as of December 31, 20171
 
 
Mineral and Royalty Interests
 
Working Interests
Resource Play2
 
Mineral Interests
 
NPRIs
 
ORRIs
 
Gross
 
Net
Bakken Shale
 
366,359

 
40,022

 
15,450

 
55,220

 
7,239

Haynesville Shale
 
360,587

 
7,335

 
28,741

 
191,523

 
55,169

Three Forks
 
355,665

 
37,203

 
13,810

 
55,422

 
6,866

Bossier Shale
 
329,717

 
1,896

 
20,530

 
178,902

 
53,753

Wolfcamp — Midland
 
288,718

 
134,284

 
124,272

 
160

 
4

Marcellus Shale
 
246,542

 

 
13,467

 

 

Canyon Lime
 
226,149

 

 

 

 

Tuscaloosa Marine Shale
 
189,147

 
23,397

 
2,192

 

 

Wolfcamp — Delaware
 
137,759

 
38,021

 
6,403

 
2,642

 
1,291

Granite Wash
 
109,876

 
5,031

 
104,308

 
4,840

 
1,254

Fayetteville Shale
 
74,401

 
4,789

 
11,861

 

 

Eagle Ford Shale
 
67,478

 
107,019

 
49,613

 
1,147

 
87

Barnett Shale
 
61,788

 
4,164

 
37,633

 
13,417

 
7,747

1  
Excludes acreage for which we have incomplete seller records.
2 
The plays above have been delineated based on information from the Energy Information Administration ("EIA"), the USGS, or state agencies, or according to areas of the most active industry development.
 










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:
 
 
As of December 31, 2017
 
Average Daily Production (Boe/d) for the Year Ended December 31,
Resource Play1
 
Acres
 
Average Ownership Interest2
 
Average Ownership Leased3
 
2017
 
2016
 
2015
Bakken Shale
 
366,359

 
17.2
%
 
76.6
%
 
1,877

 
1,659

 
1,746

Haynesville Shale
 
360,587

 
63.7
%
 
52.2
%
 
5,391

 
3,727

 
2,728

Three Forks
 
355,665

 
16.8
%
 
78.5
%
 
991

 
968

 
823

Bossier Shale
 
329,717

 
68.1
%
 
49.1
%
 
337

 
330

 
351

Wolfcamp — Midland
 
288,718

 
4.6
%
 
98.1
%
 
659

 
136

 
76

Marcellus Shale
 
246,542

 
14.4
%
 
26.9
%
 
118

 
111

 
71

Canyon Lime
 
226,149

 
30.5
%
 
30.2
%
 
67

 
16

 
8

Tuscaloosa Marine Shale
 
189,147

 
58.1
%
 
43.8
%
 
35

 
52

 
46

Wolfcamp — Delaware
 
137,759

 
9.7
%
 
97.0
%
 
785

 
437

 
148

Granite Wash
 
109,876

 
15.0
%
 
60.6
%
 
136

 
167

 
194

Fayetteville Shale
 
74,401

 
56.0
%
 
78.6
%
 
1,014

 
1,181

 
1,349

Eagle Ford Shale
 
67,478

 
14.1
%
 
85.4
%
 
1,743

 
2,095

 
2,355

Barnett Shale
 
61,788

 
15.8
%
 
57.2
%
 
172

 
181

 
239

1  
The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industry development.
2  
Ownership interest is equal to the percentage that our undivided ownership interest in a tract bears to the entire tract. The per-play average ownership interests shown above reflect the weighted average of our ownership interests in all tracts in the play. Our weighted-average mineral royalty for all of our mineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average royalty interest in our mineral and royalty interests.
3  
The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the play.  

 








13


NPRIs
The following table sets forth information about our NPRIs:
 
 
As of December 31, 2017
 
Average Daily Production (Boe/d) for the Year Ended December 31,
Resource Play1
 
Acres
 
Average Royalty Interest2
 
Average Percent Leased3
 
2017
 
2016
 
2015
Wolfcamp — Midland
 
134,284

 
0.7
%
 
82.8
%
 
25

 
11

 
22

Eagle Ford Shale
 
107,019

 
1.2
%
 
42.4
%
 
6

 
14

 
3

Bakken Shale
 
40,022

 
1.3
%
 
57.7
%
 
74

 
63

 
56

Wolfcamp — Delaware
 
38,021

 
0.6
%
 
86.7
%
 
7

 
4

 
1

Three Forks
 
37,203

 
1.2
%
 
61.3
%
 
37

 
36

 
50

Tuscaloosa Marine Shale
 
23,397

 
0.5
%
 
93.3
%
 

 

 

Haynesville Shale
 
7,335

 
4.2
%
 
96.1
%
 
443

 
167

 
325

Granite Wash
 
5,031

 
0.8
%
 
100.0
%
 
31

 
16

 
5

Fayetteville Shale
 
4,789

 
0.1
%
 
100.0
%
 
9

 
13

 

Barnett Shale
 
4,164

 
2.7
%
 
86.9
%
 
1

 
1

 

Bossier Shale
 
1,896

 
2.9
%
 
51.8
%
 
113

 
11

 
53

Canyon Lime
 

 

 

 

 

 

Marcellus Shale
 

 

 

 

 

 

1
The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industry development.
2  
Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis for the given area. NPRIs may be denominated as a “fractional royalty,” which entitles the owner to the stated fraction of gross production, or a “fraction of royalty,” where the stated fraction is multiplied by the lease royalty. In cases where our land documentation does not specify the form of NPRI, we have assumed a fractional royalty for purposes of the average royalty interests shown above.
3
The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the play.  
 










14


ORRIs
The following table sets forth information about our ORRIs:
 
 
As of December 31, 2017
 
Average Daily Production (Boe/d) for the Year Ended December 31,
Resource Play1
 
Acres
 
Average Royalty Interest2
 
2017
 
2016
 
2015
Wolfcamp — Midland
 
124,272

 
0.4
%
 
31

 
<1

 
5

Granite Wash
 
104,308

 
1.6
%
 
72

 
155

 
115

Eagle Ford Shale
 
49,613

 
2.2
%
 
193

 
95

 
204

Barnett Shale
 
37,633

 
5.0
%
 
99

 
109

 
158

Haynesville Shale
 
28,741

 
4.9
%
 
383

 
686

 
1,111

Bossier Shale
 
20,530

 
5.7
%
 
8

 
28

 
57

Bakken Shale
 
15,450

 
1.3
%
 
32

 
34

 
41

Three Forks
 
13,810

 
1.3
%
 
25

 
21

 
27

Marcellus Shale
 
13,467

 
2.3
%
 
19

 
37

 
6

Fayetteville Shale
 
11,861

 
4.0
%
 

 

 

Wolfcamp — Delaware
 
6,403

 
2.1
%
 
4

 

 

Tuscaloosa Marine Shale
 
2,192

 
13.5
%
 

 
<1

 

Canyon Lime
 

 

 

 

 

1  
The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industry development.
2
Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in this play.  
 












15


Working Interests
The following table sets forth information about our working interests.
 
 
As of December 31, 2017
 
Average Daily Production (Boe/d) for the Year Ended December 31,
Resource Play1
 
Gross Acres2
 
Net Acres2
 
2017
 
2016
 
2015
Haynesville Shale
 
191,523

 
55,169

 
9,631

 
5,077

 
2,909

Bossier Shale
 
178,902

 
53,753

 
690

 
309

 
135

Three Forks
 
55,422

 
6,866

 
194

 
491

 
551

Bakken Shale
 
55,220

 
7,239

 
347

 
864

 
792

Barnett Shale
 
13,417

 
7,747

 
51

 
87

 
104

Granite Wash
 
4,840

 
1,254

 
283

 
429

 
537

Wolfcamp — Delaware
 
2,642

 
1,291

 
143

 
150

 
23

Eagle Ford Shale
 
1,147

 
87

 

 
76

 
11

Wolfcamp — Midland
 
160

 
4

 
2

 
1

 

Canyon Lime
 

 

 
14

 

 

Fayetteville Shale
 

 

 

 
23

 

Marcellus Shale
 

 

 

 
<1

 

Tuscaloosa Marine Shale
 

 

 

 

 

1  
The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industry development.
2  
Excludes acreage that is not quantifiable due to incomplete seller records.

























16


Estimated Proved Reserves
Evaluation and Review of Estimated Proved Reserves
The reserves estimates as of December 31, 2017, 2016, and 2015 shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agenciesNSAI 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 reserves 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 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, 2017 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 32 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 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.

17


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, 2017, 2016, and 2015 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, well 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
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.

18


The following table presents our estimated proved oil and natural gas reserves:
 
As of December 31,
 
20171
 
20162
 
20153
 
(Unaudited)
Estimated proved developed reserves4:
 
 
 
 
 
Oil (MBbls)
17,891

 
18,150

 
15,497

Natural gas (MMcf)
233,017

 
223,057

 
174,555

Total (MBoe)
56,727

 
55,327

 
44,590

Estimated proved undeveloped reserves5:
 
 
 
 
 
Oil (MBbls)
8

 
218

 
345

Natural gas (MMcf)
67,257

 
47,282

 
29,120

Total (MBoe)
11,218

 
8,098

 
5,198

Estimated proved reserves:
 
 
 
 
 
Oil (MBbls)
17,899

 
18,368

 
15,842

Natural gas (MMcf)
300,274

 
270,339

 
203,675

Total (MBoe)
67,945

 
63,425

 
49,788

Percent proved developed
83.5
%
 
87.2
%
 
89.6
%
1  
Estimates of reserves as of December 31, 2017, were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period from January through December 2017. For oil volumes, the average WTI spot oil price of $51.34 per barrel is used for estimates of reserves for all the properties as of December 31, 2017. This average price is adjusted for quality, transportation fees, and market differentials.  For natural gas volumes, the average Henry Hub price of $2.98 per MMBTU is used for estimates of reserves for all the properties as of December 31, 2017. This average price is adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates exclude NGL quantities. When taking these adjustments into account, the average adjusted prices weighted by production over the remaining lives of the properties are $46.59 per barrel for oil and $2.70 per Mcf for natural gas as of December 31, 2017.
2 
Estimates of reserves as of December 31, 2016 were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period January through December 2016. For oil volumes, the average WTI spot oil price of $42.75 per barrel is used for estimates of reserves for all the properties as of December 31, 2016. These average prices are adjusted for quality, transportation fees, and market differentials.  For natural gas volumes, the average Henry Hub price of $2.48 per MMBTU is used for estimates of reserves for all the properties as of December 31, 2016. These average prices are adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates exclude NGL quantities. When taking these adjustments into account, the average adjusted prices weighted by production over the remaining lives of the properties are $37.50 per barrel for oil and $2.14 per Mcf for natural gas. 
3 
Estimates of reserves as of December 31, 2015 were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period January through December 2015. For oil volumes, the average WTI spot oil price of $50.28 per barrel is used for estimates of reserves for all the properties as of December 31, 2015. These average prices are adjusted for quality, transportation fees, and market differentials. For natural gas volumes, the average Henry Hub price of $2.59 per MMBTU is used for estimates of reserves for all the properties as of December 31, 2015. These average prices are adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates exclude NGL quantities. When taking these adjustments into account, the average adjusted gas price weighted by production over the remaining lives of the properties is $2.45 per Mcf. 
4  
Proved developed reserves of 61, 74, and 84 MBoe as of December 31, 2017, 2016, and 2015, respectively, were attributable to noncontrolling interests in our consolidated subsidiaries.
5  
As of December 31, 2017, 2016, and 2015, no proved undeveloped reserves were attributable to noncontrolling interests in our consolidated subsidiaries.

19


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, 2017, which is included as an exhibit to this Annual Report.
Estimated Proved Undeveloped Reserves
As of December 31, 2017, our PUDs comprised 8 MBbls of oil and 67,257 MMcf of natural gas, for a total of 11,218 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, 2017 (in MBoe):
 
Estimated Proved Undeveloped Reserves
 
(Unaudited)
As of December 31, 2016
8,098

Acquisitions of reserves
920

Divestiture of reserves
(672
)
Extensions and discoveries
4,564

Revisions of previous estimates
945

Transfers to estimated proved developed
(2,637
)
As of December 31, 2017
11,218

New PUD reserves totaling 4,564 MBoe were added during the year ended December 31, 2017, resulting from development activities in the Haynesville/Bossier play. There were 920 MBoe of PUD reserves acquired in the Haynesville/Bossier play. This was partially offset by the divestiture of 672 MBoe of PUD reserves associated with the farmouts to Canaan and to Pivotal.
During the year ended December 31, 2017, we had reductions of 127 Mboe PUD reserves, primarily as a result of updated operator information. This was offset by increases in previous estimates of 1,072 Mboe based on performance from offset and analog production. This resulted in a total upward revision of 945 Mboe comprised of an increase of 5,831 MMcf natural gas reserves and a decrease of 27 Mbbl of oil reserves.
Costs incurred relating to the development of locations that were classified as PUDs at December 31, 2016 were $29.3 million during the year ended December 31, 2017. Additionally, during the year ended December 31, 2017, we incurred $26.7 million drilling and completing other wells which were not classified as PUDs as of December 31, 2016. Estimated future development costs relating to the development of PUD reserves at December 31, 2017 are projected to be approximately $20.5 million. All of our PUD drilling locations as of December 31, 2017 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, 2017. As of December 31, 2017, approximately 16.5% of our total proved reserves were classified as PUDs.

20


Oil and Natural Gas Production Prices and Production Costs
Production and Price History
For the year ended December 31, 2017, 26.3% of our production and 47.1% of our oil and natural gas revenues were related to oil and condensate production and sales, respectively. During the same period, natural gas and NGL sales were 73.7% of our production and 52.9% 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,
 
 
2017
 
2016
 
2015
Production:
 
 

 
 

 
 

Oil and condensate (MBbls)1
 
3,552

 
3,680

 
3,565

Natural gas (MMcf)1
 
59,779

 
47,498

 
41,389

Total (MBoe)
 
13,515

 
11,596

 
10,463

Average daily production (MBoe/d)
 
37.0

 
31.7

 
28.7

Realized Prices2:
 
 

 
 

 
 

Oil and condensate (per Bbl)
 
$
47.78

 
$
38.69

 
$
45.87

Natural gas and natural gas liquids (per Mcf)1
 
$
3.19

 
$
2.59

 
$
2.80

Unit Cost per Boe:
 
 

 
 

 
 

Production costs and ad valorem taxes
 
$
3.51

 
$
3.06

 
$
3.42

1
As a mineral-and-royalty interest owner, we are often provided insufficient and inconsistent data by our operators related to NGLs. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. As such, the realized prices for natural gas account for all value attributable to NGLs. The oil and condensate production volumes and natural gas production volumes do not include NGL volumes.
2
Excludes the effect of commodity derivative instruments.
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, 2017, we owned mineral and royalty interests or working interests in 61,443 productive wells, which consisted of 38,112 oil wells and 23,331 natural gas wells. As of December 31, 2017, we owned mineral and royalty interests in 55,728 productive wells, which consisted of 37,189 oil wells and 18,539 natural gas wells, and working interests in 9,688 gross productive wells and 352 net productive wells, which consisted of 3,693 gross (65 net) productive oil wells and 5,995 gross (287 net) productive natural gas wells. We own both mineral and royalty interests and working interests in 3,973 of these wells.







21


Acreage
Mineral and Royalty Interests
The following table sets forth information relating to our acreage for our mineral interests as of December 31, 2017:
State
 
Developed Acreage
 
Undeveloped Acreage
 
Total Acreage
Texas
 
342,912

 
4,717,981

 
5,060,893

Oklahoma
 
116,555

 
458,278

 
574,833

Louisiana
 
35,259

 
498,331

 
533,590

Montana
 
20,844

 
545,925

 
566,769

North Dakota
 
18,016

 
1,141,046

 
1,159,062

Arkansas
 
4,887

 
1,274,169

 
1,279,056

Mississippi
 
4,576

 
2,403,176

 
2,407,752

Alabama
 
2,859

 
2,057,740

 
2,060,599

Nevada
 

 
792,588

 
792,588

Florida
 

 
743,452

 
743,452

Other
 
82,555

 
1,532,785

 
1,615,340

Total
 
628,463

 
16,165,471

 
16,793,934

The following table sets forth information relating to our acreage for our NPRIs as of December 31, 2017:
State
 
Developed Acreage
 
Undeveloped Acreage
 
Total Acreage
Texas
 
203,805

 
1,104,471

 
1,308,276

Oklahoma
 
6,976